Oil and gas production handbook An introduction to oil ... - ABB Group

Håvard Devold
Oil and gas production handbook
An introduction to oil and gas production,
transport, refining and petrochemical
industry

ISBN 978-82-997886-3-2
2

PREFACE
This handbook has been compiled for readers with an interest in the oil and
gas industry. It is an overview of the main processes and equipment. When
we searched for a suitable introduction to be used for new engineers, I
discovered that much of the equipment is described in standards, equipment
manuals and project documentation. Little material was found to quickly give
the reader an overview of the entire oil and gas industry, while still
preserving enough detail to let the engineer have an appreciation of the main
characteristics and design issues.
I have had many requests that downstream processes be included, and
have restructured the book into Upstream, Midstream, Refining and
Petrochemical, adding basic information on these facilities. The main focus
of the book is still the upstream production process.
This book is by no means a complete description on the detailed design of
any part of this process, and many details have been omitted in order to
summarize a vast subject.
The material has been compiled from various online resources, as well as
ABB and customer documents. I am grateful to my colleagues in the industry
for providing their valuable input and comments. I have included many
photos to give you, the reader, an impression of what typical facilities or
equipment look like. Non-ABB photo sources are given below pictures; other
pictures and illustrations are copyrighted by ABB.
Edition 3.0 Oslo, August 2013
Håvard Devold
©2006 - 2013 ABB Oil and Gas
Except as otherwise indicated, all materials, including but not limited to design, text, graphics,
other files, and the selection and arrangement thereof, are the copyright property of ABB, ALL
RIGHTS RESERVED. You may electronically copy and print a hard-copy of this document only
for non-commercial or personal use, within the organization that employs you, provided that the
materials are not modified and all copyright or proprietary notices are retained. Use of photos
and graphics and references from other sources in no way promotes or endorses these
products and services and is for illustration only. Pictures credited to Wikipedia are licensed
under GNU Free Documentation License (GFDL) or Public Domain (PD) and are published here
with the same license. Originals and full information can be found on www.wikimedia.org.
b

CONTENTS
1 Introduction ............................................................................................. 1
2 Facilities and processes ......................................................................... 4
2.1 Exploration ..................................................................................... 4
2.2 Production ..................................................................................... 5
2.2.1 Onshore ................................................................................ 7
2.2.2 Offshore ................................................................................ 8
2.3 Upstream process sections ......................................................... 12
2.3.1 Wellheads ........................................................................... 12
2.3.2 Manifolds and gathering ..................................................... 13
2.3.3 Separation ........................................................................... 14
2.3.4 Metering, storage and export .............................................. 15
2.3.5 Utility systems ..................................................................... 16
2.4 Midstream .................................................................................... 16
2.4.1 Gas Plants .......................................................................... 16
2.4.1 Gas compression ................................................................ 17
2.4.2 Pipelines ............................................................................. 17
2.4.1 LNG liquefaction and regasification facilities ...................... 18
2.5 Refining ....................................................................................... 18
2.6 Petrochemical .............................................................................. 19
3 Reservoir and wellheads ...................................................................... 21
3.1 Crude oil and natural gas ............................................................ 21
3.1.1 Crude oil .............................................................................. 21
3.1.2 Natural gas .......................................................................... 23
3.1.3 Condensates ....................................................................... 24
3.2 The reservoir ............................................................................... 24
3.3 Exploration and drilling ................................................................ 26
3.4 The well ....................................................................................... 29
3.4.1 Well casing .......................................................................... 29
3.4.2 Completion .......................................................................... 31
3.5 Wellhead ...................................................................................... 32
3.5.1 Subsea wells ....................................................................... 34
3.5.2 Injection ............................................................................... 35
3.6 Artificial lift ................................................................................... 35
3.6.1 Rod pumps .......................................................................... 35
3.6.2 ESP ..................................................................................... 36
3.6.3 Gas lift ................................................................................. 36
3.6.4 Plunger lift ........................................................................... 37
3.7 Well workover, intervention and stimulation ................................ 38
4 The upstream oil and gas process ....................................................... 40
41
4.1 Manifolds and gathering .............................................................. 42
I

4.1.1 Pipelines and risers ............................................................ 42
4.1.2 Production, test and injection manifolds ............................. 42
4.2 Separation ................................................................................... 43
4.2.1 Test separators and well test .............................................. 43
4.2.2 Production separators ......................................................... 43
4.2.3 Second stage separator ...................................................... 45
4.2.4 Third stage separator .......................................................... 45
4.2.5 Coalescer ............................................................................ 46
4.2.6 Electrostatic desalter .......................................................... 46
4.2.7 Water treatment .................................................................. 46
4.3 Gas treatment and compression ................................................. 48
4.3.1 Heat exchangers ................................................................. 48
4.3.2 Scrubbers and reboilers ...................................................... 49
4.3.3 Compressors, anti-surge and performance ........................ 50
4.4 Oil and gas storage, metering and export ................................... 55
4.4.1 Fiscal metering .................................................................... 55
4.4.2 Storage ............................................................................... 57
4.4.3 Marine loading .................................................................... 58
5 Midstream facilities ............................................................................... 59
5.1 Gathering ..................................................................................... 59
5.2 Gas plants ................................................................................... 59
5.2.1 Gas composition ................................................................. 59
5.3 Gas processing ............................................................................ 62
5.3.1 Acid gas removal ................................................................ 63
5.3.2 Dehydration ......................................................................... 64
5.3.3 Mercury removal ................................................................. 64
5.3.4 Nitrogen rejection ................................................................ 65
5.3.5 NGL recovery and treatment .............................................. 65
5.3.6 Sales gas specifications ..................................................... 65
5.4 Pipelines ...................................................................................... 67
5.4.1 Pipeline terminal ................................................................. 67
5.4.2 Gas Pipelines, compressor and valve stations ................... 67
5.4.3 Liquid pipelines, pump and valve stations .......................... 68
5.4.4 Pipeline management, control and safety .......................... 69
5.5 LNG ............................................................................................. 70
5.5.1 LNG liquefaction ................................................................. 71
5.5.2 Storage, transport and regasification .................................. 76
6 Refining ................................................................................................ 77
6.1 Fractional distillation .................................................................... 77
6.2 Basic products ............................................................................. 78
6.3 Upgrading and advanced processes ........................................... 80
6.4 Blending and distribution ............................................................. 85
7 Petrochemical ....................................................................................... 87
II

7.1 Aromatics ..................................................................................... 88
7.1.1 Xylene and polyester chain ................................................. 89
7.1.2 Toluene, benzene, polyurethane and phenolic chain ......... 90
7.1.3 Benzene and styrenic chain, derivatives ............................ 91
7.2 Olefins ......................................................................................... 92
7.2.1 Ethylene, derivatives ........................................................... 93
7.2.2 Propylene, derivatives ........................................................ 94
7.2.3 Butadiene, butylenes, and pygas, derivatives .................... 96
7.3 Synthesis gas (syngas) ............................................................... 97
7.3.1 Methanol based products ................................................... 98
7.3.2 Ammonia based products ................................................... 99
8 Utility systems .................................................................................... 100
8.1 Process control systems............................................................ 100
8.1.1 Safety systems and functional safety ............................... 103
8.1.2 Emergency shutdown and process shutdown .................. 105
8.1.3 Fire and gas system ......................................................... 107
8.1.4 Control and safety configuration ....................................... 108
8.1.5 Telemetry/SCADA ............................................................ 110
8.2 Digital oilfield ............................................................................. 111
8.2.1 Reservoir management and drilling operations ................ 112
8.2.2 Production optimization .................................................... 112
8.2.3 Asset optimization and maintenance support ................... 113
8.2.4 Information management systems (IMS).......................... 115
8.2.5 Training simulators ........................................................... 116
8.3 Power generation, distribution and drives ................................. 117
8.4 Flare and atmospheric ventilation ............................................. 119
8.5 Instrument air ............................................................................. 120
8.6 HVAC ......................................................................................... 120
8.7 Water systems ........................................................................... 120
8.7.1 Potable water .................................................................... 120
8.7.2 Seawater ........................................................................... 121
8.7.3 Ballast water ..................................................................... 121
8.8 Chemicals and additives ........................................................... 121
8.9 Telecom ..................................................................................... 124
9 Unconventional and conventional resources and environmental effects
127
9.1 Unconventional sources of oil and gas ...................................... 127
9.1.1 Extra heavy crude ............................................................. 128
9.1.2 Tar sands .......................................................................... 128
9.1.3 Oil shale ............................................................................ 129
9.1.4 Shale gas and coal bed methane ..................................... 130
9.1.5 Coal, gas to liquids and synthetic fuel .............................. 131
9.1.6 Methane hydrates ............................................................. 132
III

9.1.7 Biofuels ............................................................................. 133
9.1.8 Hydrogen .......................................................................... 135
9.2 Emissions and environmental effects ........................................ 135
9.2.1 Indigenous emissions ....................................................... 136
9.2.2 Greenhouse emissions ..................................................... 136
9.2.3 Carbon capture and sequestration ................................... 139
10 Units ................................................................................................... 141
11 Glossary of terms and acronyms ....................................................... 143
12 References ......................................................................................... 147
13 Index ................................................................................................... 148
-
IV

1 Introduction
Oil has been used for lighting purposes for many thousands of years. In
areas where oil is found in shallow reservoirs, seeps of crude oil or gas may
naturally develop, and some oil could simply be collected from seepage or
tar ponds.
Historically, we know the tales of eternal fires where oil and gas seeps
ignited and burned. One example is the site where the famous oracle of
Delphi was built around 1,000 B.C. Written sources from 500 B.C. describe
how the Chinese used natural gas to boil water.
It was not until 1859 that "Colonel" Edwin Drake drilled the first successful oil
well, with the sole purpose of finding oil. The Drake Well was located in the
middle of quiet farm country in northwestern Pennsylvania, and sparked the
international search for an industrial use for petroleum.
Photo: Drake Well Museum Collection, Titusville, PA
These wells were shallow by modern standards, often less than 50 meters
deep, but they produced large quantities of oil. In this picture of the Tarr
Farm, Oil Creek Valley, the Phillips well on the right initially produced 4,000
1

arrels per day in October, 1861, and the Woodford well on the left came in
at 1,500 barrels per day in July, 1862.
The oil was collected in the wooden tank pictured in the foreground. As you
will no doubt notice, there are many different-sized barrels in the
background. At this time, barrel size had not been standardized, which made
statements like "oil is selling at $5 per barrel" very confusing (today a barrel
is 159 liters (see units on p. 141). But even in those days, overproduction
was something to be avoided. When the "Empire well" was completed in
September 1861, it produced 3,000 barrels per day, flooding the market, and
the price of oil plummeted to 10 cents a barrel. In some ways, we see the
same effect today. When new shale gas fields in the US are constrained by
the capacity of the existing oil and gas pipeline network, it results in
bottlenecks and low prices at the production site.
Soon, oil had replaced most other fuels for motorized transport. The
automobile industry developed at the end of the 19 th century, and quickly
adopted oil as fuel. Gasoline engines were essential for designing successful
aircraft. Ships driven by oil could move up to twice as fast as their coalpowered
counterparts, a vital military advantage. Gas was burned off or left
in the ground.
Despite attempts at gas transportation as far back as 1821, it was not until
after World War II that welding techniques, pipe rolling, and metallurgical
advances allowed for the construction of reliable long distance pipelines,
creating a natural gas industry boom. At the same time, the petrochemical
industry with its new plastic materials quickly increased production. Even
now, gas production is gaining market share as liquefied natural gas (LNG)
provides an economical way of transporting gas from even the remotest
sites.
With the appearance of automobiles and more advanced consumers, it was
necessary to improve and standardize the marketable products. Refining
was necessary to divide the crude in fractions that could be blended to
precise specifications. As value shifted from refining to upstream production,
it became even more essential for refineries to increase high-value fuel yield
from a variety of crudes. From 10-40% gasoline for crude a century ago, a
modern refinery can get up to 70% gasoline from the same quality crude
through a variety of advanced reforming and cracking processes.
Chemicals derived from petroleum or natural gas – petrochemicals – are an
essential part of the chemical industry today. Petrochemistry is a fairly young
2

industry; it only started to grow in the 1940s, more than 80 years after the
drilling of the first commercial oil well.
During World War II, the demand for synthetic materials to replace costly
and sometimes less efficient products caused the petrochemical industry to
develop into a major player in modern economy and society.
Before then, it was a tentative, experimental sector, starting with basic
materials:
• Synthetic rubbers in the 1900s
• Bakelite, the first petrochemical-derived plastic, in 1907
• First petrochemical solvents in the 1920s
• Polystyrene in the 1930s
And it then moved to an incredible variety of areas:
• Household goods (kitchen appliances, textiles, furniture)
• Medicine (heart pacemakers, transfusion bags)
• Leisure (running shoes, computers...)
• Highly specialized fields like archaeology and crime detection
With oil prices of $100 a barrel or more, even more difficult-to-access
sources have become economically viable. Such sources include tar sands
in Venezuela and Canada, shale oil and gas in the US (and developing
elsewhere), coal bed methane and synthetic diesel (syndiesel) from natural
gas, and biodiesel and bioethanol from biological sources have seen a
dramatic increase over the last ten years. These sources may eventually
more than triple the potential reserves of hydrocarbon fuels. Beyond that,
there are even more exotic sources, such as methane hydrates, that some
experts claim can double available resources once more.
With increasing consumption and ever-increasing conventional and
unconventional resources, the challenge becomes not one of availability, but
of sustainable use of fossil fuels in the face of rising environmental impacts,
that range from local pollution to global climate effects.
3

2 Facilities and processes
The oil and gas industry facilities and systems are broadly defined,
according to their use in the oil and gas industry production stream:
Exploration
Upstream
Midstream
Refining
Includes prospecting, seismic and drilling activities that take
place before the development of a field is finally decided.
Typically refers to all facilities for production and stabilization
of oil and gas. The reservoir and drilling community often
uses upstream for the wellhead, well, completion and
reservoir only, and downstream of the wellhead as
production or processing. Exploration and
upstream/production together is referred to as E&P.
Broadly defined as gas treatment, LNG production and
regasification plants, and oil and gas pipeline systems.
Where oil and condensates are processed into marketable
products with defined specifications such as gasoline, diesel
or feedstock for the petrochemical industry. Refinery offsites
such as tank storage and distribution terminals are included
in this segment, or may be part of a separate distributions
operation.
Petrochemical These products are chemical products where the main
feedstock is hydrocarbons. Examples are plastics, fertilizer
and a wide range of industrial chemicals.
2.1 Exploration
In the past, surface features
such as tar seeps or gas
pockmarks provided initial
clues to the location of
shallow hydrocarbon
deposits. Today, a series of
surveys, starting with broad
geological mapping through
increasingly advanced
methods such as passive
seismic, reflective seismic,
magnetic and gravity surveys give data to sophisticated analysis tools that
identify potential hydrocarbon bearing rock as “prospects.” Chart: Norwegian
Petroleum Directorate (Barents Sea)
4

An offshore well typically costs $30 million, with most falling in the $10-$100
million range. Rig leases are typically $200,000 - $700,000 per day. The
average US onshore well costs about $4 million, as many have much lower
production capacity. Smaller companies exploring marginal onshore fields
may drill a shallow well for as little as $100,000.
This means that oil companies spend much time on analysis models of good
exploration data, and will only drill when models give a good indication of
source rock and probability of finding oil or gas. The first wells in a region are
called wildcats because little may be known about potential dangers, such as
the downhole pressures that will be encountered, and therefore require
particular care and attention to safety equipment.
If a find (strike, penetration) is made, additional reservoir characterization
such as production testing, appraisal wells, etc., are needed to determine the
size and production capacity of the reservoir in order to justify a development
decision.
2.2 Production
This illustration gives an overview of typical oil and gas production facilities:
Figure 1. Oil and gas production facilities
5

Although there is a wide range of sizes and layouts, most production
facilities have many of the same processing systems shown in this simplified
overview:
Production
Wellheads
Production
and Test
Manifolds
LP
Gas compressors
HP
Metering and
storage
Gas
Meter
Export
Pig
Launcher
Gas
Pipeline
Production Separators
Pig
Launcher
Oil
Pipeline
1 stage
Tanker
Loading
2 stage
ø
Crude
pump
Oil
Meter
Water treatment
Test Separator
Oil Storage
Drilling
Utility systems (selected)
Injection
wells
Injection
manifold
Power Generation
Water injection
pump
Mud and Cementing
Instrument Air
Gas injection
compressor
Potable Water
Firefighting
systems
HVAC
Figure 2. Oil and gas production overview
6

Today, oil and gas is produced in almost every part of the world, from the
small 100 barrels-a-day private wells to the large bore 4,000 barrels-a-day
wells; in shallow 20 meter deep reservoirs to 3,000 meter deep wells in more
than 2,000 meters of water; in $100,000 onshore wells and $10 billion
offshore developments. Despite this range, many parts of the process are
quite similar in principle.
At the left side, we find the wellheads. They feed into production and test
manifolds. In distributed production, this is called the gathering system. The
remainder of the diagram is the actual process, often called the gas oil
separation plant (GOSP). While there are oil- or gas-only installations, more
often the well-stream will consist of a full range of hydrocarbons from gas
(methane, butane, propane, etc.), condensates (medium density
hydrocarbons) to crude oil. With this well flow, we also get a variety of
unwanted components, such as water, carbon dioxide, salts, sulfur and
sand. The purpose of the GOSP is to process the well flow into clean,
marketable products: oil, natural gas or condensates. Also included are a
number of utility systems, which are not part of the actual process but
provide energy, water, air or some other utility to the plant.
2.2.1 Onshore
Onshore production is economically
viable from a few dozen barrels of oil
a day and upward. Oil and gas is
produced from several million wells
worldwide. In particular, a gas
gathering network can become very
large, with production from thousands
of wells, several hundred
kilometers/miles apart, feeding
through a gathering network into a
processing plant. This picture shows a
well, equipped with a sucker rod pump
(donkey pump) often associated with
onshore oil production. However, as
we shall see later, there are many
other ways of extracting oil from a non
free-flowing well. For the smallest reservoirs, oil is simply collected in a
holding tank and picked up at regular intervals by tanker truck or railcar to be
processed at a refinery.
Onshore wells in oil-rich areas are also high capacity wells producing
thousands of barrels per day, connected to a 1,000,000 barrel or more per
7

day GOSP. Product is sent from the plant by pipeline or tankers. The
production may come from many different license owners, so metering of
individual well-streams into the gathering network are important tasks.
Unconventional plays target very
heavy crude and tar sands that
became economically extractable
with higher prices and new
technology. Heavy crude may
need heating and diluents to be
extracted. Tar sands have lost
their volatile compounds and are
strip-mined or can be extracted
with steam. It must be further
processed to separate bitumen
from the sand. Since about 2007,
drilling technology and fracturing
of the reservoir have allowed
shale gas and liquids to be
produced in increasing volumes.
This allows the US in particular to
reduce dependence on
hydrocarbon imports. Canada,
China, Argentina, Russia, Mexico
and Australia also rank among the
top unconventional plays. These
unconventional reserves may
contain more 2-3 times the
hydrocarbons found in conventional reservoirs. These pictures show the
Syncrude Mildred plant at Athabasca, Canada Photo: GDFL Jamitzky/Wikimedia
and the Marcellus Shale in Pennsylvania. Photo: GDFL Ruhrfisch /Wikimedia
2.2.2 Offshore
A whole range of different structures is used offshore, depending on size and
water depth. In the last few years, we have seen pure sea bottom
installations with multiphase piping to shore, and no offshore topside
structure at all. Replacing outlying wellhead towers, deviation drilling is used
to reach different parts of the reservoir from a few wellhead cluster locations.
Some of the common offshore structures are:
8

Shallow water complex, which
is characterized by several
independent platforms with
different parts of the process
and utilities linked with gangway
bridges. Individual platforms
include wellhead riser,
processing, accommodations
and power generation platforms.
(This picture shows the BP
Valhall complex.) Typically found
in water depths up to 100
meters.
Gravity base consists of enormous
concrete fixed structures placed on the
bottom, typically with oil storage cells in
a "skirt" that rests on the sea bottom.
The large deck receives all parts of the
process and utilities in large modules.
Large fields at 100 to 500 meters of
water depth were typical in the 1980s
and 1990s. The concrete was poured at
an onshore location, with enough air in
the storage cells to keep the structure
floating until tow-out and lowering onto
the seabed. The picture shows the
world's largest GBS platform, Troll A,
during construction. Photo Statoil
Compliant towers are much like fixed
platforms. They consist of a narrow
tower, attached to a foundation on the
seafloor and extending up to the
platform. This tower is flexible, as
opposed to the relatively rigid legs of a
fixed platform. Flexibility allows it to operate in much deeper water, as it can
absorb much of the pressure exerted by the wind and sea. Compliant towers
are used between 500 and 1,000 meters of water depth.
Floating production, where all topside systems are located on a floating
structure with dry or subsea wells. Some floaters are:
9

FPSO: Floating Production,
Storage and Offloading. Their
main advantage is that they are a
standalone structure that does not
need external infrastructure such
as pipelines or storage. Crude oil
is offloaded to a shuttle tanker at
regular intervals, from days to
weeks, depending on production
and storage capacity. FPSOs
currently produce from around
10,000 to 200,000 barrels per day.
An FPSO is typically a tanker type
hull or barge, often converted from
an existing crude oil tanker (VLCC
or ULCC). Due to the increasing
sea depth for new fields, they
dominate new offshore field
development at more than 100
meters water depth.
The wellheads or subsea risers
from the sea bottom are located
on a central or bow-mounted
turret, so that the ship can rotate
freely to point into wind, waves or
current. The turret has wire rope
and chain connections to several
anchors (position mooring -
POSMOOR), or it can be
dynamically positioned using
thrusters (dynamic positioning –
DYNPOS). Most installations use
subsea wells. The main process is
placed on the deck, while the hull
is used for storage and offloading
to a shuttle tanker. It may also be
used for the transportation of
pipelines.
FPSOs with additional processing
and systems, such as drilling and
production and stranded gas LNG
production are planned.
10

A variation of the FPSO is the Sevan Marine design. This uses a circular hull
which shows the same profile to wind, waves and current, regardless of
direction. It shares many of the characteristics of the ship-shaped FPSO,
such as high storage capacity and deck load, but does not rotate and
therefore does not need a rotating turret. Photo: Sevan Marine
Tension Leg Platform (TLP –
left side in picture) consists of
a structure held in place by
vertical tendons connected to
the sea floor by pile-secured
templates. The structure is
held in a fixed position by
tensioned tendons, which
provide for use of the TLP in a
broad water depth range up to
about 2,000m. The tendons
are constructed as hollow high
tensile strength steel pipes that
carry the spare buoyancy of
the structure and ensure
limited vertical motion.
Semi-submersible platforms
(front of picture) have a similar
design but without taut
mooring. This permits more
lateral and vertical motion and
is generally used with flexible
risers and subsea wells.
Similarly, Seastar platforms are
miniature floating tension leg
platforms, much like the semisubmersible
type, with
tensioned tendons.
SPAR consists of a single tall
floating cylindrical hull,
supporting a fixed deck. The
cylinder does not, however,
extend all the way to the
seabed. Rather, it is tethered to
the bottom by a series of cables and lines. The large cylinder serves to
stabilize the platform in the water, and allows for movement to absorb the
force of potential hurricanes. SPARs can be quite large and are used for
11

water depths from 300 up to 3,000 meters. SPAR is not an acronym, and is
named for its resemblance to a ship's spar. SPARs can support dry
completion wells, but are more often used with subsea wells.
Subsea production systems are wells located on the sea floor, as opposed
to the surface. As in a floating production system, the petroleum is extracted
at the seabed, and is then “tied-back” to a pre-existing production platform or
even an onshore facility, limited by horizontal distance or "offset.” The well is
drilled by a movable rig and the extracted oil and natural gas is transported
by undersea pipeline and riser to a processing facility. This allows one
strategically placed production platform to service many wells over a
reasonably large area. Subsea systems are typically used at depths of 500
meters or more and do not have the ability to drill, only to extract and
transport. Drilling and
completion is performed
from a surface rig.
Horizontal offsets of up
to 250 kilometers/150
miles are currently
possible. The aim of the
industry is to allow fully
autonomous subsea
production facilities,
with multiple wellpads,
processing, and direct
tie-back to shore. Photo:
Statoil
2.3 Upstream process sections
We will go through each section in detail in the following chapters. The
summary below is an introductory synopsis of each section. The activities up
to the producing wellhead (drilling, casing, completion, wellhead) are often
called “pre-completion,” while the production facility is “post-completion.” For
conventional fields, they tend to be roughly the same in initial capital
expenditure.
2.3.1 Wellheads
The wellhead sits on top of the actual oil or gas well leading down to the
reservoir. A wellhead may also be an injection well, used to inject water or
gas back into the reservoir to maintain pressure and levels to maximize
production.
12

Once a natural gas or oil
well is drilled and it has
been verified that
commercially viable
quantities of natural gas
are present for extraction,
the well must be
“completed” to allow
petroleum or natural gas
to flow out of the
formation and up to the
surface. This process
includes strengthening
the well hole with casing,
evaluating the pressure
and temperature of the formation, and installing the proper equipment to
ensure an efficient flow of natural gas from the well. The well flow is
controlled with a choke.
We differentiate between, dry completion (which is either onshore or on the
deck of an offshore structure) and subsea completions below the surface.
The wellhead structure, often called a Christmas tree, must allow for a
number of operations relating to production and well workover. Well
workover refers to various technologies for maintaining the well and
improving its production capacity.
2.3.2 Manifolds and gathering
Onshore, the individual
well streams are brought
into the main production
facilities over a network of
gathering pipelines and
manifold systems. The
purpose of these pipelines
is to allow setup of
production "well sets" so
that for a given production
level, the best reservoir
utilization well flow
composition (gas, oil,
water), etc., can be
selected from the available wells.
13

For gas gathering systems, it is common to meter the individual gathering
lines into the manifold as shown in this picture. For multiphase flows
(combination of gas, oil and water), the high cost of multiphase flow meters
often leads to the use of software flow rate estimators that use well test data
to calculate actual flow.
Offshore, the dry completion wells on the main field center feed directly into
production manifolds, while outlying wellhead towers and subsea
installations feed via multiphase pipelines back to the production risers.
Risers are a system that allows a pipeline to "rise" up to the topside
structure. For floating structures, this involves a way to take up weight and
movement. For heavy crude and in Arctic areas, diluents and heating may
be needed to reduce viscosity and allow flow.
2.3.3 Separation
Some wells have pure gas
production which can be
taken directly for gas
treatment
and/or
compression. More often,
the well produces a
combination of gas, oil and
water, with various
contaminants that must be
separated and processed.
The production separators
come in many forms and
designs, with the classic
variant being the gravity
separator. Photo: JL Bryan
Oilfield Equipment
In gravity separation, the well flow is fed into a horizontal vessel. The
retention period is typically five minutes, allowing gas to bubble out, water to
settle at the bottom and oil to be taken out in the middle. The pressure is
often reduced in several stages (high pressure separator, low pressure
separator, etc.) to allow controlled separation of volatile components. A
sudden pressure reduction might allow flash vaporization leading to
instability and safety hazards.
14

2.3.4 Metering, storage and export
Most plants do not allow
local gas storage, but oil
is often stored before
loading on a vessel, such
as a shuttle tanker taking
oil to a larger tanker
terminal, or direct to a
crude carrier. Offshore
production facilities
without a direct pipeline
connection generally rely
on crude storage in the
base or hull, allowing a
shuttle tanker to offload about once a week. A larger production complex
generally has an associated tank farm terminal allowing the storage of
different grades of crude to take up changes in demand, delays in transport,
etc.
Metering stations allow operators to monitor and manage the natural gas
and oil exported from the production installation. These employ specialized
meters to measure the natural gas or oil as it flows through the pipeline,
without impeding its movement.
This metered volume
represents a transfer of
ownership from a producer
to a customer (or another
division within the
company), and is called
custody transfer metering.
It forms the basis for
invoicing the sold product
and also for production
taxes and revenue sharing
between partners.
Accuracy requirements are
often set by governmental authorities.
Typically, a metering installation consists of a number of meter runs so that
one meter will not have to handle the full capacity range, and associated
prover loops so that the meter accuracy can be tested and calibrated at
regular intervals.
15

2.3.5 Utility systems
Utility systems are systems which do not handle the hydrocarbon process
flow, but provide some service to the main process safety or residents.
Depending on the location of the installation, many such functions may be
available from nearby infrastructure, such as electricity. Many remote
installations are fully self-sustaining and must generate their own power,
water, etc.
2.4 Midstream
The midstream part of the value chain is often defined as gas plants, LNG
production and regasification, and oil and gas pipeline transport systems.
2.4.1 Gas Plants
Gas processing consists of
separating the various
hydrocarbons and fluids
from the pure natural gas to
produce what is known as
“pipeline quality” dry natural
gas. Major transportation
pipelines usually impose
restrictions on the makeup
of natural gas that is
allowed into the pipeline.
Before the natural gas can
be transported it must be
purified.
Figure 3. Midstream facilities
Whatever the source of the
16

natural gas, once separated from crude oil (if present) it commonly exists in
mixtures with other hydrocarbons, principally ethane, propane, butane and
pentanes. In addition, raw natural gas contains water vapor, hydrogen
sulfide (H2S), carbon dioxide, helium, nitrogen and other compounds.
Associated hydrocarbons, known as “natural gas liquids” (NGL), are used as
raw materials for oil refineries or petrochemical plants and as sources of
energy.
2.4.1 Gas compression
Gas from a pure natural
gas wellhead might have
sufficient pressure to feed
directly into a pipeline
transport system. Gas from
separators has generally
lost so much pressure that
it must be recompressed to
be transported. Turbinedriven
compressors gain
their energy by using a
small proportion of the
natural gas that they
compress. The turbine
itself serves to operate a centrifugal compressor, which contains a type of
fan that compresses and pumps the natural gas through the pipeline. Some
compressor stations are operated by using an electric motor to turn the
centrifugal compressor. This type of compression does not require the use of
any natural gas from the pipe; however, it does require a reliable source of
electricity nearby. The compression includes a large section of associated
equipment such as scrubbers (to remove liquid droplets) and heat
exchangers, lube oil treatment, etc.
2.4.2 Pipelines
Pipelines can measure anywhere from 6 to 48 inches (15-120 cm) in
diameter. In order to ensure their efficient and safe operation, operators
routinely inspect their pipelines for corrosion and defects. This is done with
sophisticated pieces of equipment known as “pigs.” Pigs are intelligent
robotic devices that are propelled down pipelines to evaluate the interior of
the pipe. Pigs can test pipe thickness, roundness, check for signs of
corrosion, detect minute leaks, and any other defect along the interior of the
pipeline that may either restrict the flow of gas, or pose a potential safety risk
17

for the operation of the
pipeline. Sending a pig
down a pipeline is fittingly
known as “pigging.” The
export facility must contain
equipment to safely insert
and retrieve pigs from the
pipeline as well as
depressurization, referred
to as pig launchers and
pig receivers.
Loading on tankers
involves loading systems, ranging from tanker jetties to sophisticated singlepoint
mooring and loading systems that allow the tanker to dock and load the
product, even in bad weather.
2.4.1 LNG liquefaction and regasification facilities
Natural gas that is mainly
methane cannot be
compressed to liquid
state at normal ambient
temperature. Except for
special uses such as
compressed natural gas
(CNG), the only practical
solution to long distance
gas transportation when
a pipeline is not available
or economical is to
produce LNG at -162 °C.
This requires one or
more cooling stages. Cooling work consumes 6-10% of the energy to be
transported. Special insulated tank LNG carriers are required for
transportation, and at the receiving end, a regasification terminal heats the
LNG to vaporization for pipeline distribution. Photo: Cove Point LNG Regas terminal
2.5 Refining
Refining aims to provide a defined range of products according to agreed
specifications. Simple refineries use a distillation column to separate crude
into fractions, and the relative quantities are directly dependent on the crude
used. Therefore, it is necessary to obtain a range of crudes that can be
18

lended to a suitable
feedstock to produce the
required quantity and
quality of end products.
Photo: Statoil Mongstad Refinery
The economic success of a
modern refinery depends
on its ability to accept
almost any available crude.
With a variety of processes
such as cracking,
reforming, additives and
blending, it can provide product in quantity and quality to meet market
demand at premium prices.
The refinery operations often include product distribution terminals for
dispensing product to bulk customers such as airports, gasoline stations,
ports and industries.
2.6 Petrochemical
Chemicals derived from petroleum or natural gas – petrochemicals – are an
essential part of today’s chemical industry. Petrochemical plants produce
thousands of chemical compounds. The main feedstock is natural gas,
condensates (NGL) and other refinery byproducts such as naphtha, gasoil,
and benzene. Petrochemical plants are divided into three main primary
product groups according to their feedstock and primary petrochemical
product:
Olefins include ethylene, propylene, and butadiene. These are the main
sources of plastics (polyethylene, polyester, PVC), industrial chemicals and
synthetic rubber.
Aromatics include benzene, toluene, and xylenes, which also are a source
of plastics (polyurethane, polystyrene, acrylates, nylon), as well as synthetic
detergents and dyes.
Synthesis gas (syngas) is formed by steam reforming between methane
and steam to create a mixture of carbon monoxide and hydrogen. It is used
to make ammonia, e.g., for fertilizer urea, and methanol as a solvent and
chemical intermediary. Syngas is also feedstock for other processes such as
the Fischer–Tropsch process that produces synthetic diesel.
19

Photo: DOW, Terneusen, Netherlands
20

3 Reservoir and wellheads
There are three main types of conventional wells. The most common is an oil
well with associated gas. Natural gas wells are drilled specifically for natural
gas, and contain little or no oil. Condensate wells contain natural gas, as well
as a liquid condensate. This condensate is a liquid hydrocarbon mixture that
is often separated from the natural gas either at the wellhead, or during the
processing of the natural gas. Depending on the well type, completion may
differ slightly. It is important to remember that natural gas, being lighter than
air, will naturally rise to the surface of a well. Consequently, lifting equipment
and well treatment are not necessary in many natural gas and condensate
wells, while for oil wells, many types of artificial lift may be installed,
particularly as the reservoir pressure falls during years of production.
There is no distinct transition from conventional to unconventional oil and
gas production. Lower porosity (tighter reservoirs) and varying maturity
create a range of shale oil and gas, tight gas, heavy oil, etc., that is simply
an extension of the conventional domain.
3.1 Crude oil and natural gas
3.1.1 Crude oil
Crude oil is a complex mixture consisting of 200 or more different organic
compounds, mostly alkanes (single bond hydrocarbons on the form C n H 2n+2 )
and smaller fraction aromatics (six-ring molecules such as benzene C 6 H 6 )
Figure 4. Basic hydrocarbons
Different crude contains different combinations and concentrations of these
various compounds. The API (American Petroleum Institute) gravity of a
21

particular crude is merely a measure of its specific gravity or density. The
higher the API number expressed as degrees API, the less dense (lighter,
thinner) the crude. Simply put, this means that the lower the degrees API,
the denser (heavier, thicker) the crude. Crude from different fields and from
different formations within a field can be similar in composition or
significantly different.
In addition to API grade and hydrocarbons, crude is characterized for other
undesired elements like sulfur, which is regulated and needs to be removed.
Crude oil API gravities typically range from 7 to 52, corresponding to about
970 kg/m 3 to 750 kg/m 3 , but most fall in the 20 to 45 API gravity range.
Although light crude (i.e., 40-45 degrees API) is considered the best, lighter
crude (i.e., 46 degree API and above) is generally no better for a typical
refinery. As the crude gets lighter than 40-45 degrees API, it contains shorter
molecules, which means a lower carbon number. This also means it contains
less of the molecules useful as high octane gasoline and diesel fuel, the
production of which most refiners try to maximize. If a crude is heavier than
35 degrees API, it contains longer and bigger molecules that are not useful
as high octane gasoline and diesel fuel without further processing.
For crude that has undergone detailed physical and chemical property
analysis, the API gravity can be used as a rough index of the quality of
crudes of similar composition as they naturally occur (that is, without
adulteration, mixing, blending, etc.). When crudes of a different type and
quality are mixed, or when different petroleum components are mixed, API
gravity cannot be used meaningfully for anything other than a measure of
fluid density.
For instance, consider a
barrel of tar that is
dissolved in 3 barrels of
naphtha (lighter fluid) to
produce 4 barrels of a
40 degrees API mixture.
When this 4-barrel
mixture is fed to a
distillation column at the
inlet to a refinery, one
barrel of tar plus 3
barrels of naphtha is all
that will come out of the
still. On the other hand,
4 barrels of a naturally
22

occurring 40 degrees API crude, fed to the distillation column at the refinery
could come out of the still as 1.4 barrels of gasoline and naphtha (typically
C 8 H 18 ), 0.6 barrels of kerosene (jet fuel C 12-15 ), 0.7 barrels of diesel fuel
(average C 12 H 26 ), 0.5 barrels of heavy distillate (C 20-70 ), 0.3 barrels of
lubricating stock, and 0.5 barrels of residue (bitumen, mainly poly-cyclic
aromatics).
The previous figure illustrates weight percent distributions of three different
hypothetical petroleum stocks that could be fed to a refinery with catalytic
cracking capacity. The chemical composition is generalized by the carbon
number which is the number of carbon atoms in each molecule - C n H 2n+2 . A
medium blend is desired because it has the composition that will yield the
highest output of high octane gasoline and diesel fuel in the cracking
refinery. Though the heavy stock and the light stock could be mixed to
produce a blend with the same API gravity as the medium stock, the
composition of the blend would be very different from the medium stock, as
the figure indicates. Heavy crude can be processed in a refinery by cracking
and reforming that reduces the carbon number to increase the high value
fuel yield.
3.1.2 Natural gas
The natural gas used by consumers is composed almost entirely of
methane. However, natural gas found at the wellhead, though still composed
primarily of methane, is not pure. Raw natural gas comes from three types of
wells: oil wells, gas wells, and condensate wells.
Natural gas that comes from oil wells is typically termed “associated gas.”
This gas can exist separately from oil in the formation (free gas), or
dissolved in the crude oil (dissolved gas). Natural gas from gas and
condensate wells in which there is little or no crude oil, is termed “nonassociated
gas.”
Gas wells typically produce only raw natural gas. However condensate wells
produce free natural gas along with a semi-liquid hydrocarbon condensate.
Whatever the source of the natural gas, once separated from crude oil (if
present), it commonly exists in mixtures with other hydrocarbons, principally
ethane, propane, butane, and pentanes. In addition, raw natural gas
contains water vapor, hydrogen sulfide (H 2 S), carbon dioxide, helium,
nitrogen, and other compounds.
23

3.1.3 Condensates
While the ethane, propane, butane, and pentanes must be removed from
natural gas, this does not mean that they are all waste products. In fact,
associated hydrocarbons, known as natural gas liquids (NGL), can be very
valuable byproducts of natural gas processing. NGLs include ethane,
propane, butane, iso-butane, and natural gasoline. These are sold
separately and have a variety of different uses such as raw materials for oil
refineries or petrochemical plants, as sources of energy, and for enhancing
oil recovery in oil wells. Condensates are also useful as diluents for heavy
crude.
3.2 The reservoir
The oil and gas bearing structure is typically porous rock, such as sandstone
or washed out limestone. The sand may have been laid down as desert sand
dunes or seafloor. Oil and gas deposits form as organic material (tiny plants
and animals) deposited in earlier geological periods, typically 100 to 200
million years ago, under, over or with the sand or silt, are transformed by
high temperature and pressure into hydrocarbons.
Anticline Fault Salt dome
Gas
Porous rock
Oil
Impermeable rock
Fossil water in porous reservoir rock
Figure 5. Reservoir formations
For an oil reservoir to form, porous rock needs to be covered by a nonporous
layer such as salt, shale, chalk or mud rock that prevent the
hydrocarbons from leaking out of the structure. As rock structures become
folded and raised as a result of tectonic movements, the hydrocarbons
migrate out of the deposits and upward in porous rock and collect in crests
under the non-permeable rock, with gas at the top and oil and fossil water at
24

the bottom. Salt is a thick fluid, and if deposited under the reservoir, it will
flow up in heavier rock over millions of years. This process creates salt
domes with a similar reservoir-forming effect. These are common e.g. in the
Middle East.
This extraordinary process is ongoing. However, an oil reservoir matures in
the sense that an immature formation may not yet have allowed the
hydrocarbons to form and collect. A young reservoir generally has heavy
crude, less than 20 API, and is often Cretaceous in origin (65-145 million
years ago). Most light crude reservoirs tend to be Jurassic or Triassic (145-
205/205-250 million years ago), and gas reservoirs where the organic
molecules are further broken down are often Permian or Carboniferous in
origin (250-290/290-350 million years ago).
In some areas, strong uplift, erosion and cracking of the rock above have
allowed hydrocarbons to leak out, leaving heavy oil reservoirs or tar pools.
Some of the world's largest oil deposits are tar sands, where the volatile
compounds have evaporated from shallow sandy formations, leaving huge
volumes of bitumen-soaked sands. These are often exposed at the surface
and can be strip-mined, but must be separated
from the sand with hot water, steam and
diluents, and further processed with cracking
and reforming in a refinery to improve fuel
yield.
101 kPa
10 °C
The oil and gas is pressurized in the pores of
the absorbent formation rock. When a well is
drilled into the reservoir structure, the
hydrostatic formation pressure drives the
hydrocarbons out of the rock and up into the
well. When the well flows, gas, oil and water
are extracted, and the levels shift as the
reservoir is depleted. The challenge is to plan
drilling so that reservoir utilization can be
maximized.
20 MPa
100 °C
40 MPa
200 °C
Gas expands
and pushes oil
downwards
Seismic data and advanced 3D visualization
models are used to plan extraction. Even so,
the average recovery rate is only 40%, leaving
60% of the hydrocarbons trapped in the
reservoir. The best reservoirs with advanced enhanced oil recovery (EOR)
allow up to 70% recovery. Reservoirs can be quite complex, with many folds
and several layers of hydrocarbon-bearing rock above each other (in some
areas more than ten). Modern wells are drilled with large horizontal offsets to
25
Reservoir hydrostatic pressure
pushes oil and gas upwards.

each different parts of the structure and with multiple completions so that
one well can produce from several locations.
3.3 Exploration and drilling
When 3D seismic investigation has been completed, it is time to drill the well.
Normally, dedicated drilling rigs either on mobile onshore units or offshore
floating rigs are used. Larger production platforms may also have their own
production drilling equipment.
The main components of the
drilling rig are the derrick, floor,
drawworks, drive and mud
handling. Control and power can
be hydraulic or electric.
Earlier pictures of drillers and
roughnecks working with rotary
tables (bottom drives) are now
replaced with top drive and semiautomated
pipe handling on larger
installations. The hydraulic or
electric top drive hangs from the derrick crown and gives pressure and
rotational torque to the drill string. The whole assembly is controlled by the
drawworks. Photo: Puna Geothermal Venture
The drill string is assembled
from pipe segments about 30
meters (100 feet) long, normally
with conical inside threads at
one end and outside at the
other. As each 30 meter
segment is drilled, the drive is
disconnected and a new pipe
segment inserted in the string. A
cone bit is used to dig into the
rock. Different cones are used
for different types of rock and at
different stages of the well. The
picture above shows roller cones with inserts (on the left). Other bits are
PDC (polycrystalline diamond compact, on the right) and diamond
impregnated. Photo: Kingdream PLC
26

As the well is sunk into the ground, the weight of the drill string increases
and might reach 500 metric tons or more for a 3,000 meter deep well. The
drawwork and top drive must be precisely controlled so as not to overload
and break the drill string or the cone. Typical values are 50kN force on the
bit and a torque of 1-1.5 kNm at 40-80 RPM for an 8-inch cone. Rate of
penetration (ROP) is very dependent on depth and could be as much as
20m per hour for shallow sandstone and dolomite (chalk), and as low as 1m
per hour on deep shale rock and granite.
Directional drilling is
intentional deviation of a
well bore from the vertical.
It is often necessary to drill
at an angle from the
vertical to reach different
parts of the formation.
Controlled directional
drilling makes it possible to
reach subsurface areas
laterally remote from the
point where the bit enters
the earth. It often involves
the use of a drill motor
driven by mud pressure mounted directly on the cone (mud motor, turbo drill,
and dyna-drill), whipstocks – a steel casing that bends between the drill pipe
and cone, or other deflecting rods, also used for horizontal wells and multiple
completions, where one well may split into several bores. A well that has
sections of more than 80 degrees from the vertical is called a horizontal well.
Modern wells are drilled with large horizontal offsets to reach different parts
of the structure and achieve higher production. The world record is more
than 15 km. Multiple completions allow production from several locations.
Wells can be of any depth from near the surface to a depth of more than
6,000 meters. Oil and gas are typically formed at 3,000-4,000 meters depth,
but part of the overlying rock may have since eroded away. The pressure
and temperature generally increase with increasing depth, so that deep wells
can have more than 200 ºC temperature and 90 MPa pressure (900 times
atmospheric pressure), equivalent to the hydrostatic pressure set by the
distance to the surface. The weight of the oil in the production string reduces
wellhead pressure. Crude oil has a specific weight of 790 to 970 kg per cubic
meter. For a 3,000 meter deep well with 30 MPa downhole pressure and
normal crude oil at 850 kg/m 3 , the wellhead static pressure will only be
27

around 4.5 MPa. During production, the pressure will drop further due to
resistance to flow in the reservoir and well.
The mud enters though the drill pipe, passes through the cone and rises in
the uncompleted well. Mud serves several purposes:
• It brings rock shales (fragments of rock) up to the surface
• It cleans and cools the cone
• It lubricates the drill pipe string and cone
• Fibrous particles attach to the well surface to bind solids
• Mud weight should balance the downhole pressure to avoid leakage
of gas and oil. Often, the well will drill though smaller pockets of
hydrocarbons, which may cause a “blow-out" if the mud weight
cannot balance the pressure. The same might happen when drilling
into the main reservoir.
To prevent an uncontrolled blow-out, a subsurface safety valve is often
installed. This valve has enough closing force to seal off the well and cut the
drill string in an uncontrollable blow-out situation. However, unless casing is
already also in place, hydrocarbons may also leave though other cracks
inside the well and rise to the surface through porous or cracked rock. In
addition to fire and pollution hazards, dissolved gas in seawater rising under
a floating structure significantly reduces buoyancy.
The mud mix is a
special brew designed
to match the desired
flow thickness,
lubrication properties
and specific gravity.
Mud is a common name
used for all kinds of
fluids used in drilling
completion and
workover and can be
oil-based, water-based
or synthetic, and
consists of powdered
clays such as bentonite, oil, water and various additives and chemicals such
as caustic soda, barite (sulfurous mineral), lignite (brown coal), polymers and
emulsifiers. Photo: OSHA.gov
A special high-density mud called “kill fluid” is used to shut down a well for
workover.
28

Mud is recirculated. Coarse rock shales are separated in a shale shaker
before it is passed though finer filters and recalibrated with new additives
before returning to the mud holding tanks.
3.4 The well
Once the well has been drilled, it must be completed. Completing a well
consists of a number of steps, such as installing the well casing, completion,
installing the wellhead, and installing lifting equipment or treating the
formation, if required.
3.4.1 Well casing
Installing the well casing
is an important part of the
drilling and completion
process. Well casing
consists of a series of
metal tubes installed in
the freshly drilled hole.
Casing serves to
strengthen the sides of
the well hole, ensure that
no oil or natural gas
seeps out as it is brought
to the surface, and keep
other fluids or gases from
seeping into the
formation through the
well. A good deal of planning is necessary to ensure that the right casing for
each well is installed. Types of casing used depend on subsurface
characteristics of the well, including the diameter of the well (which is
dependent on the size of the drill bit used) and the pressures and
temperatures experienced. In most wells, the diameter of the well hole
decreases the deeper it is drilled, leading to a conical shape that must be
taken into account when installing casing. The casing is normally cemented
in place. Ill: wikipedia.org
There are five different types of well casing. They include:
• Conductor casing, which is usually no more than 20 to 50 feet (7-
17 m) long, is installed before main drilling to prevent the top of the
29

well from caving in and to help in the process of circulating the
drilling fluid up from the bottom of the well.
• Surface casing is the next type of casing to be installed. It can be
anywhere from 100 to 400 meters long, and is smaller in diameter to
fit inside the conductor casing. Its primary purpose is to protect fresh
water deposits near the surface of the well from contamination by
leaking hydrocarbons or salt water from deeper underground. It also
serves as a conduit for drilling mud returning to the surface and
helps protect the drill hole from damage during drilling.
• Intermediate casing is usually the longest section of casing found
in a well. Its primary purpose is to minimize the hazards associated
with subsurface formations that may affect the well. These include
abnormal underground pressure zones, underground shales and
formations that might otherwise contaminate the well, such as
underground salt water deposits. Liner strings are sometimes used
instead of intermediate casing. Liner strings are usually just attached
to the previous casing with “hangers” instead of being cemented into
place, and are thus less permanent.
• Production casing, alternatively called the “oil string” or '”long
string,” is installed last and is the deepest section of casing in a well.
This is the casing that provides a conduit from the surface of the well
to the petroleum-producing formation. The size of the production
casing depends on a number of considerations, including the lifting
equipment to be used, the number of completions required, and the
possibility of deepening the well at a later date. For example, if it is
expected that the well will be deepened later, then the production
casing must be wide enough to allow the passage of a drill bit later
on. It is also instrumental in preventing blow-outs, allowing the
formation to be “sealed” from the top should dangerous pressure
levels be reached.
Once the casing is installed, tubing is inserted inside the casing, from the
opening well at the top to the formation at the bottom. The hydrocarbons that
are extracted run up this tubing to the surface. The production casing is
typically 5 to 28 cm (2 -11 in) with most production wells being 6 inches or
more. Production depends on reservoir, bore, pressure, etc., and may be
less than 100 barrels per day to several thousand barrels per day. (5,000
bpd is about 555 liters/minute). A packer is used between casing and tubing
at the bottom of the well.
30

3.4.2 Completion
Well completion commonly refers to the process of finishing a well so that it
is ready to produce oil or natural gas. In essence, completion consists of
deciding on the characteristics of the intake portion of the well in the targeted
hydrocarbon formation. There are a number of types of completions,
including:
• Open hole completions are the most basic type and are only used
in very competent formations that are unlikely to cave in. An open
hole completion consists of simply running the casing directly down
into the formation, leaving the end of the piping open without any
other protective filter.
• Conventional perforated completions consist of production casing
run through the formation. The sides of this casing are perforated,
with tiny holes along the sides facing the formation, which allows
hydrocarbons to flow into the well hole while still providing a suitable
amount of support and protection for the well hole. In the past, “bullet
perforators” were used. These were essentially small guns lowered
into the well that sent off small bullets to penetrate the casing and
cement. Today, “jet perforating” is preferred. This consists of small,
electrically-fired charges that are lowered into the well. When ignited,
these charges poke tiny holes through to the formation, in the same
manner as bullet perforating.
• Sand exclusion completions are designed for production in an
area that contains a large amount of loose sand. These completions
are designed to allow for the flow of natural gas and oil into the well,
while preventing sand from entering. The most common methods of
keeping sand out of the well hole are screening or filtering systems.
Both of these types of sand barriers can be used in open hole and
perforated completions.
• Permanent completions are those in which the completion and
wellhead are assembled and installed only once. Installing the
casing, cementing, perforating and other completion work is done
with small-diameter tools to ensure the permanent nature of the
completion. Completing a well in this manner can lead to significant
cost savings compared to other types.
• Multiple zone completion is the practice of completing a well such
that hydrocarbons from two or more formations may be produced
simultaneously, without mixing with each other. For example, a well
may be drilled that passes through a number of formations on its
way deeper underground, or it may be more desirable in a horizontal
31

well to add multiple completions to drain the formation most
effectively. When it is necessary to separate different completions,
hard rubber “packing” instruments are used to maintain separation.
• Drainhole completions are a form of horizontal or slanted drilling.
This type of completion consists of drilling out horizontally into the
formation from a vertical well, essentially providing a drain for the
hydrocarbons to run down into the well. These completions are more
commonly associated with oil wells than with natural gas wells.
3.5 Wellhead
Wellheads can involve dry or subsea completion. Dry completion means that
the well is onshore or on the topside structure on an offshore installation.
Subsea wellheads are located underwater on a special sea bed template.
The wellhead has equipment
mounted at the opening of the well to
regulate and monitor the extraction of
hydrocarbons from the underground
formation. This also prevents oil or
natural gas leaking out of the well,
and prevents blow-outs due to high
pressure formations. Formations that
are under high pressure typically
require wellheads that can withstand
a great deal of upward pressure from
the escaping gases and liquids.
These must be able to withstand
pressures of up to 140 MPa (1,400
Bar). The wellhead consists of three
components: the casing head, the
tubing head, and the “Christmas tree.”
Photo: Vetco Gray
A typical Christmas tree, composed of
a master gate valve, a pressure
gauge, a wing valve, a swab valve
and a choke is shown above. The
Christmas tree may also have a number of check valves. The functions of
these devices are explained below. Ill: Vetco Gray
At the bottom we find the casing head and casing hangers.
The casing is screwed, bolted or welded to the hanger. Several valves and
plugs are normally fitted to give access to the casing. This permits the casing
32

to be opened, closed, bled down, and in some cases, allow the flowing well
to be produced through the casing as well as the tubing. The valve can be
used to determine leaks in casing, tubing or the packer, and is also used for
lift gas injection into the casing.
The tubing hanger (also
called a donut) is used to
position the tubing correctly in
the well. Sealing also allows
Christmas tree removal with
pressure in the casing.
Master gate valve. The
master gate valve is a high
quality valve. It provides full
opening, which means that it
opens to the same inside
diameter as the tubing so that
specialized tools may be run
through it. It must be capable
of holding the full pressure of
the well safely for all
anticipated purposes. This
valve is usually left fully open
and is not used to control flow.
Pressure gauge. The
minimum instrumentation is a
pressure gauge placed above
the master gate valve before
the wing valve. In addition,
other instruments such as a
temperature gauge are
normally fitted.
Wing valve. The wing valve can be a gate or ball valve. When shutting in
the well, the wing gate or valve is normally used so that the tubing pressure
can be easily read.
Swab valve. The swab valve is used to gain access to the well for wireline
operations, intervention and other workover procedures (see below). On top
of it is a tree adapter and cap that mates with a range of equipment.
33

Variable flow choke valve. The variable flow choke valve is typically a large
needle valve. Its calibrated opening is adjustable in 1/64 inch increments
(called beans). High-quality steel is used in order to withstand the highspeed
flow of abrasive materials that pass through the choke, usually over
many years, with little damage except to the dart or seat. If a variable choke
is not required, a less expensive positive choke is normally installed on
smaller wells. This has a built-in restriction that limits flow when the wing
valve is fully open.
Vertical tree. Christmas trees can also be horizontal where the master,
wing and choke are on a horizontal axis. This reduces the height and may
allow easier intervention. Horizontal trees are especially used on subsea
wells.
3.5.1 Subsea wells
Subsea wells are essentially the
same as dry completion wells.
Mechanically, however, they are
placed in a subsea structure
(template) that allows the wells to
be drilled and serviced remotely
from the surface, and protected
from damage, e.g., from trawlers.
The wellhead is placed in a slot
in the template where it mates to
the outgoing pipeline as well as
hydraulic and electric control
signals. Ill: Statoil
Control is from the
surface, where a hydraulic
power unit (HPU)
provides power to the
subsea installation via an
umbilical. The umbilical
is a composite cable
containing tension wires,
hydraulic pipes, electrical
power, control and
communication signals. A
control pod with inert gas and/or oil protection contains control electronics,
and operates most equipment via hydraulic switches. More complex subsea
solutions may contain subsea separation/stabilization and electrical
34

multiphase pumping. This may be necessary if reservoir pressure is low,
offset (distance to main facility) is long or there are flow assurance problems
so that the gas and liquids will not stably flow to the surface.
The product is piped back through pipelines and risers to the surface. The
main choke may be located topside.
3.5.2 Injection
Wells are also divided into production and injection wells. The former are for
production of oil and gas. Injection wells are drilled to inject gas or water into
the reservoir. The purpose of injection is to maintain overall and hydrostatic
reservoir pressure and force the oil toward the production wells. When
injected water reaches the production well, it is called “injected water
breakthrough.” Special logging instruments, often based on radioactive
isotopes added to injection water, are used to detect breakthrough.
Injection wells are fundamentally the same as production wellheads. The
difference is their direction of flow and, therefore, mounting of some
directional components, such as the choke.
3.6 Artificial lift
Production wells are free flowing or lifted. A free flowing oil well has enough
downhole pressure to reach suitable wellhead production pressure and
maintain an acceptable well flow. If the formation pressure is too low, and
water or gas injection cannot maintain pressure or are not suitable, the well
must be artificially lifted. For smaller wells, 0.7 MPa (100 PSI) wellhead
pressure with a standing column of liquid in the tubing is measured, by a rule
of-thumb method, to allow the well to flow. Larger wells will be equipped with
artificial lift to increase production, even at much higher pressures. Some
artificial lift methods are:
3.6.1 Rod pumps
Sucker rod
pumps, also
called donkey
or beam
pumps, are the
most common
artificial lift
system used in
land-based
operations. A
35

motor drives a reciprocating beam, connected to a polished rod passing into
the tubing via a stuffing box. The sucker rod continues down to the oil level
and is connected to a plunger with a valve.
On each upward stroke, the plunger lifts a volume of oil up and through the
wellhead discharge. On the downward stroke it sinks (it should sink, and not
be pushed) allowing oil to flow though the valve. The motor speed and
torque is controlled for efficiency and minimal wear with a pump off controller
(PoC). Use is limited to shallow reservoirs down to a few hundred meters,
and flows up to about 40 liters (10 gallons) per stroke.
3.6.2 ESP
A downhole pump inserts
the whole pumping
mechanism into the well. In
modern installations, an
electrical submerged pump
(ESP) is inserted into the
well. Here, the whole
assembly consisting of a
long narrow motor and a
multiphase pump, such as a
progressive cavity pump
(PCP) or centrifugal pump,
hangs by an electrical cable
with tension members down
the tubing. Ill: Wikipedia.org
Installations down to 3.7 km with power up to 750 kW have been installed. At
these depths and power ratings, medium voltage drives (up to 5kV) must be
used.
ESPs work in deep reservoirs, but are sensitive to contaminants such as
sand, and efficiency is sensitive to gas oil ration (GOR) (where gas over 10%
dramatically lowers efficiency.
3.6.3 Gas lift
A gas lift injects gas into the well flow. The downhole reservoir pressure to
the wellhead falls off, due to the counter pressure from weight of the oil
column in the tubing. Thus, a 150 MPa reservoir pressure at 1,600 meters
36

will fall to zero in the
wellhead if the specific
gravity is 800 kg/m 2 (0.8
times water). By injecting
gas into this oil, the
specific gravity is lowered
and the well will start to
flow. Typically, gas is
injected between the
casing and tubing, and a
release valve on a gas lift
mandrel is inserted into
the tubing above the
packer.
The valve will open at a
set pressure to inject lift
gas into the tubing.
Several mandrels with
valves set at different
pressure ranges can be used to improve lifting and startup. Ill: Schlumberger
oilfield glossary
Gas lift can be controlled for a single well to optimize production, and to
reduce slugging effects where the gas droplets collect to form large bubbles
that can upset production. Gas lift can also be optimized over several wells
to use available gas in the most efficient way.
3.6.4 Plunger lift
The plunger lift is normally used on low pressure gas wells with some
condensate, oil or water, or high GOR wells. In this case, the well flow
conditions can be such that liquid starts to collect downhole and eventually
blocks gas so that the well production stops. In this case, a plunger with an
open/close valve can be inserted in the tubing. A plunger catcher at the top
opens the valve and can hold the plunger, while another mechanism
downhole closes the valve.
37

The cycle starts with the plunger falling into the well with its valve open.
Condensed gas and oil can pass though the plunger until it reaches bottom.
There the valve is
closed, now with a
volume of oil,
condensate or water
on top. Gas pressure
starts to accumulate
under the plunger and
after a time pushes
the plunger upwards,
with liquid on top,
which eventually flows
out of the wellhead
discharge.
When the plunger
reaches the wellhead
plunger catcher, the
valve opens and
allows gas to flow
freely for some time
while new liquid
collects at the bottom.
After a preset time, the
catcher releases the
plunger and the cycle repeats.
3.7 Well workover, intervention and stimulation
After operating for some time, a well may become less productive or faulty
due to residue buildup, sand erosion, corrosion or reservoir clogging.
Well workover is the process of performing major maintenance on an oil or
gas well. This might include replacement of the tubing, a cleanup or new
completions, new perforations and various other maintenance works such as
the installation of gas lift mandrels, new packing, etc.
Through-tubing workover operation is work performed with special tools that
do not require the time-consuming full workover procedure involving
replacement or removal of tubing. Well maintenance without killing the well
and performing full workover is time-saving and often called well
intervention. Various operations that are performed by lowering instruments
or tools on a wire into the well are called wireline operations.
38

Work on the reservoir such as chemical injection, acid treatment, heating,
etc., is referred to as reservoir stimulation. Stimulation serves to correct
various forms of structure damage and improve flow. Damage is a generic
term for accumulation of particles and fluids that block fractures and pores
and limit reservoir permeability.
• Acids, such as hydrochloric acid (HCL) are used to open up
calcareous reservoirs and to treat accumulation of calcium
carbonates in the reservoir structure around the well. Several
hundred liters of acid (typically 15% solution in water) are pumped
into the well under pressure to increase permeability of the
formation. When the pressure is high enough to open the fractures,
the process is called fracture acidizing. If the pressure is lower, it is
called matrix acidizing.
• Hydraulic fracturing is an operation in which a specially blended
liquid is pumped down a well and into a formation under pressure
high enough to cause the formation to crack open, forming passages
through which oil can flow into the well bore. Sand grains, aluminum
pellets, walnut shells, glass beads, or similar materials (propping
agents) are carried in suspension by this fluid into the fractures.
When the pressure is released at the surface, the fractures partially
close on the propping agents, leaving channels for oil to flow through
to the well. The fracture channels may be up to 100 meters long.
Hydraulic fracturing is an essential technology for unconventional
shale gas and liquids extraction.
• Explosive fracturing uses explosives to fracture a formation. At the
moment of detonation, the explosion furnishes a source of highpressure
gas to force fluid into the formation. The rubble prevents
fracture healing, making the use of propping agents unnecessary.
• Damage removal refers to other forms of removing formation
damage, such as flushing out of drill fluids.
Flexible coiled tubing can be wound around a large diameter drum and
inserted or removed much quicker than tubing installed from rigid pipe
segments. Well workover equipment including coiled tubing is often mounted
on well workover rigs.
39

4 The upstream oil and gas process
The oil and gas process is the process equipment that takes the product
from the wellhead manifolds and delivers stabilized marketable products, in
the form of crude oil, condensates or gas. Components of the process also
exist to test products and clean waste products such as produced water.
An example process for
the Statoil Njord floater
is shown on the next
page. This is a
medium-size platform
with one production
train and a production
of 40-45,000 bpd of
actual production after
the separation of water
and gas. The
associated gas and
water are used for
onboard power
generation and gas
reinjection. There is only one separation and gas compression train. The
water is treated and released (it could also have been reinjected). This
process is quite representative of hundreds of similar sized installations, and
only one more complete gas treatment train for gas export is missing to form
a complete gas production facility. Currently, Njord sends the oil via a short
pipeline to a nearby storage floater. On gravity base platforms, floating
production and storage operations (FPSO) and onshore plants, storage a
part of the main installation if the oil is not piped out directly. Photo: Statoil ASA
A large number of connections to chemicals, flares, etc., are also shown.
These systems will be described separately.
Nård main process illustration (next page): Statoil
40

4.1 Manifolds and gathering
4.1.1 Pipelines and risers
This facility uses subsea production wells. The typical high pressure (HP)
wellhead at the bottom right, with its Christmas tree and choke, is located on
the sea bed. A production riser (offshore) or gathering line (onshore) brings
the well flow into the manifolds. As the reservoir is produced, wells may fall
in pressure and become low pressure (LP) wells.
This line may include several check valves. The choke, master and wing
valves are relatively slow. Therefore, in the case of production shutdown, the
pressure on the first sectioning valve closed will rise to the maximum
wellhead pressure before these valves can close. The pipelines and risers
are designed with this in mind.
Short pipeline distances are not a problem, but longer distances may cause
a multiphase well flow to separate and form severe slugs – plugs of liquid
with gas in between – traveling in the pipeline. Severe slugging may upset
the separation process and cause overpressure safety shutdowns. Slugging
may also occur in the well as described earlier. Slugging can be controlled
manually by adjusting the choke, or by automatic slug controls. Additionally,
areas of heavy condensate may form in the pipelines. At high pressure,
these plugs may freeze at normal sea temperature, e.g., if production is shut
down or with long offsets. This can be prevented by injecting ethylene glycol.
Glycol injection is not used at Njord.
The Njord floater has topside chokes for subsea wells. The diagram also
shows that kill fluid, essentially high specific gravity mud, can be injected into
the well before the choke.
4.1.2 Production, test and injection manifolds
Check valves allow each well to be routed into one or more of several
manifold lines. There will be at least one for each process train plus
additional manifolds for test and balancing purposes. In this diagram, we
show three: test, low pressure and high pressure manifolds. The test
manifold allows one or more wells to be routed to the test separator. Since
there is only one process train, the HP and LP manifolds allow groups of HP
and LP wells to be taken to the first and second stage separators
respectively. The chokes are set to reduce the wellhead flow and pressure to
the desired HP and LP pressures respectively.
42

The desired setting for each well and which of the wells produce at HP and
LP for various production levels are defined by reservoir specialists to
ensure optimum production and recovery rate.
4.2 Separation
As described earlier, the well-stream may consist of crude oil, gas,
condensates, water and various contaminants. The purpose of the
separators is to split the flow into desirable fractions.
4.2.1 Test separators and well test
Test separators are used to separate the well flow from one or more wells for
analysis and detailed flow measurement. In this way, the behavior of each
well under different pressure flow conditions can be defined. This normally
takes place when the well is taken into production and later at regular
intervals (typically 1-2 months), and will measure the total and component
flow rates under different production conditions. Undesirable consequences
such as slugging or sand can also be determined. The separated
components are analyzed in the laboratory to determine hydrocarbon
composition of the gas oil and condensate.
Test separators can also be used to produce fuel gas for power generation
when the main process is not running. Alternatively, a three phase flow
meter can be used to save weight.
4.2.2 Production
separators
The main separators shown
here are gravity types. On
the right, you see the main
components around the first
stage separator. As
mentioned before, the
production choke reduces
well pressure to the HP
manifold and first stage
separator to about 3-5 MPa
(30-50 times atmospheric
pressure). Inlet temperature
is often in the range of 100-
150 ºC. On the example
43

platform, the well stream is colder due to subsea wells and risers.
The pressure is often
reduced in several
stages. In this
instance, three stages
are used to allow the
controlled separation of
volatile components.
The idea is to achieve
maximum liquid
recovery and stabilized
oil and gas, and to
separate water. A large
pressure reduction in a single separator will cause flash vaporization, leading
to instability and safety hazards.
The retention period is typically 5 minutes, allowing gas to bubble out, water
to settle at the bottom and oil to be taken out in the middle. In this platform
the water cut (percentage water in the well flow) is almost 40%, which is
quite high. In the first stage separator, the water content is typically reduced
to less than 5%.
At the crude entrance, there is a baffle slug catcher that will reduce the
effect of slugs (large gas bubbles or liquid plugs). However, some turbulence
is desirable as this will release gas bubbles faster than a laminar flow.
At the end, there are barriers up to a certain level to keep back the
separated oil and water. The main control loops are the oil level control loop
(EV0101 20 above) controlling the oil flow out of the separator on the right,
and the gas pressure loop at the top (FV0105 20, above). The loops are
operated by the control system. Another important function is to prevent gas
blow-by, which happens when a low oil level causes gas to exit via the oil
output, causing high pressure downstream. There are generally many more
instruments and control devices mounted on the separator. These will be
discussed later.
The liquid outlets from the separator will be equipped with vortex breakers
to reduce disturbance on the liquid table inside. This is basically a flange trap
to break any vortex formation and ensure that only separated liquid is tapped
off and not mixed with oil or water drawn in through these vortices. Similarly,
the gas outlets are equipped with demisters, essential filters that remove
liquid droplets in the gas.
44

Emergency valves (EVs) are sectioning valves that separate the process
components and blow-down valves, allowing excess hydrocarbons to burn
off in the flare. These valves are operated if critical operating conditions are
detected or on manual command from a dedicated emergency shutdown
system. This may involve partial shutdown and shutdown sequences, since
the flare may not be able to handle a full blow-down of all process sections
simultaneously.
A 45,000 bpd design production with gas and 40% water cut will give about
10 cubic meters from the wellheads per minute. There also needs to be
enough capacity to handle normal slugging from wells and risers. This
means the separator has to be about 100 cubic meters, e.g., a cylinder 3m in
diameter and 14m in length at the rated operating pressure. This means a
very heavy piece of equipment, typically around 50 tons for this size, which
limits the practical number of stages. Other types of separators, such as
vertical separators or cyclones (centrifugal separation), can be used to save
weight, space or improve separation (to be discussed later).
There must also be a certain minimum pressure difference between each
stage to allow satisfactory performance in the pressure and level control
loops. Chemical additives will also be discussed later.
4.2.3 Second stage separator
The second stage separator is quite similar to the first stage HP separator. In
addition to output from the first stage, it also receives production from wells
connected to the low pressure manifold. The pressure is now around 1 MPa
(10 atmospheres) and temperature below 100ºC. The water content will be
reduced to below 2%.
An oil heater can be located between the first and second stage separator to
reheat the oil/water/gas mixture. This makes it easier to separate out water
when initial water cut is high and temperature is low. The heat exchanger is
normally a tube/shell type where oil passes though tubes in a heating
medium placed inside an outer shell.
4.2.4 Third stage separator
The final separator is a two-phase separator, also called a flash drum. The
pressure is now reduced to atmospheric pressure of around 100 kPa, so that
the last heavy gas components can boil out. In some processes where the
initial temperature is low, it might be necessary to heat the liquid again (in a
heat exchanger) before the flash drum to achieve good separation of the
heavy components. There are level and pressure control loops.
45

As an alternative, when production is mainly gas, and remaining liquid
droplets have to be separated out, the two-phase separator can be a knockout
drum (K.O. drum).
4.2.5 Coalescer
After the third stage separator, the oil can go to a coalescer for final removal
of water. In this unit, water content can be reduced to below 0.1%. The
coalescer is completely filled with liquid: water at the bottom and oil on top.
Internal electrodes form an electric field to break surface bonds between
conductive water and isolating oil in an oil-water emulsion. The coalescer
field plates are generally steel, sometimes covered with dielectric material to
prevent short-circuits. The critical field strength in oil is in the range of 0.2 to
2 kV/cm. Field intensity and frequency as well as the coalescer grid layout
are different for different manufacturers and oil types.
4.2.6 Electrostatic desalter
If the separated oil
contains unacceptable
amounts of salts, they
can be removed in an
electrostatic desalter
(not used in the Njord
example). The salts,
which may be sodium,
calcium or magnesium
chlorides, come from the reservoir water and are also dissolved in the oil.
The desalters will be placed after the first or second stage separator
depending on GOR and water cut. Photo: Burgess Manning Europe PLC
4.2.7 Water treatment
On an installation such as this, where the water cut is high, there will be a
huge amount of water produced. In our example, a water cut of 40% gives
water production of about 4,000 cubic meters per day (4 million liters) that
must be cleaned before discharge to sea. Often, this water contains sand
particles bound to the oil/water emulsion.
46

The environmental regulations in most countries are quite strict. For
example, in the Northeast Atlantic, the OSPAR convention limits oil in water
discharged to sea to 40 mg/liter (ppm).
Figure 6. Produced water treatment
It also places limits on other forms of contaminants. This still means that the
equivalent of up to one barrel of oil per day in contaminants from the above
production is discharged into the sea, but in this form, microscopic oil drops
are broken down quickly by natural bacteria.
Various pieces of equipment are used. This illustration shows a typical water
treatment system. Water from the separators and coalescers first goes to a
sand cyclone, which removes most of the sand. The sand is further washed
before it is discharged.
The water then goes to a hydrocyclone, a centrifugal separator that
removes oil drops. The hydrocyclone creates a standing vortex where oil
collects in the middle and water is forced to the side.
Finally the water is collected in the water de-gassing drum. Dispersed gas
slowly rises and pulls remaining oil droplets to the surface by flotation. The
surface oil film is drained, and the produced water can be discharged to sea.
Recovered oil in the water treatment system is typically recycled to the third
stage separator.
47

4.3 Gas treatment and compression
The gas train consists of several stages, each taking gas from a suitable
pressure level in the production separator's gas outlet, and from the previous
stage.
A typical stage is
shown on the right.
Incoming gas (on
the right) is first
cooled in a heat
exchanger. It then
passes through the
scrubber to remove
liquids and goes into
the compressor. The
anti-surge loop
(thin orange line)
and the surge valve
(UV0121 23) allow
the gas to
recirculate. The
components are described below.
4.3.1 Heat exchangers
For the compressor to operate efficiently, gas temperature should be low.
The lower the temperature, the less energy will be used to compress the gas
for the given final pressure
and temperature. However,
both gas from separators
and compressed gas are
relatively hot. When gas is
compressed, it must remain
in thermodynamic balance,
which means that the gas
pressure times the volume
over the temperature
(PV/T) must remain
constant. (PV = nkT). This
ends up as a temperature
increase.
48

Heat exchangers of various forms are used to cool the gas. Plate heat
exchangers (upper picture) consist of a number of plates where the gas and
cooling medium pass between alternating plates in opposing directions.
Tube and shell exchangers (next picture) place tubes inside a shell filled with
cooling fluid. The cooling fluid is often pure water with corrosion inhibitors.
When designing the
process, it is important to
plan the thermal energy
balance. Heat should be
conserved, e.g., by using
the cooling fluid from the
gas train to reheat oil in the
oil train. Excess heat is
dispersed, e.g., by
seawater cooling.
However, hot seawater is
extremely corrosive, so
materials with high
resistance to corrosion,
such as titanium must be
used. Photo: SEC Shell and
Tube Heat Exchanges
4.3.2 Scrubbers and reboilers
The separated gas may contain mist and other liquid droplets. Drops of
water and hydrocarbons also form when the gas is cooled in the heat
exchanger, and must be removed before it reaches the compressor. If liquid
droplets enter the compressor, they will erode the fast rotating blades. A
scrubber is designed to remove small fractions of liquid from the gas.
There are various types of gas-drying equipment available, but the most
common suction (compressor) scrubber is based on dehydration by
absorption in triethylene glycol (TEG). The scrubber consists of many levels
of glycol layers.
A large number of gas traps (enlarged detail) force the gas to bubble up
through each glycol layer as it flows from the bottom to the top of each
section.
Processed glycol is pumped in at the top from the holding tank. It flows from
level to level against the gas flow as it spills over the edge of each trap.
49

During this process, it absorbs liquids from the gas and comes out as rich
glycol at the bottom. The holding tank also functions as a heat exchanger for
liquid, to and from the reboilers.
The glycol is recycled by removing the absorbed liquid. This is done in the
reboiler, which is filled with rich glycol and heated to boil out the liquids at
temperature of about 130-180 °C (260-350 °F) for a number of hours.
Usually there is a distillation column on the gas vent to further improve
separation of glycol and other hydrocarbons. For higher capacity, there are
often two reboilers which alternate between heating rich glycol and draining
recycled processed glycol. On a standalone unit, the heat is supplied from a
burner that uses the recovered vaporized hydrocarbons. In other designs,
heating will be a combination of hot cooling substances from other parts of
the process and electric heaters, and recycling the hydrocarbon liquids to the
third stage separator.
Figure 7, Glycol regeneration
4.3.3 Compressors, anti-surge and performance
Compressors are used in many parts of the oil and gas process, from
upstream production to gas plants, pipelines, LNG and petrochemical plants.
The overview given here will therefore be referenced from other sections.
Several types of compressors are used for gas compression, each with
different characteristics such as operating power, speed, pressure and
volume:
50

• Reciprocating compressors, which use a piston and cylinder design
with 2-2 cylinders are
built up to about 30
MW power, around
500-1,800 rpm (lower
for higher power) with
pressure up to 5MPa
(500 bars). Used for
lower capacity gas
compression and
high reservoir
pressure gas injection. Photo: Ariel corp.
• Screw compressors
are manufactured up to
several
MW,
synchronous speed
(3,000/3,600 rpm) and
pressure up to about
2.5 MPa (25 bar). Two
counter-rotating screws
with matching profiles
provide positive
displacement and a
wide operating range.
Typical use is natural
gas gathering.
Photo:
mfg.
Mycom/Mayekawa
• Axial blade and fin
type compressors
with up to 15 wheels
provide high volumes at
a relatively low
pressure differential
(discharge pressure 3-5
times inlet pressure),
speeds of 5,000-8,000
rpm, and inlet flows up
to 200,000 m 3 /hour.
Applications include air compressors and cooling compression in LNG
plants. Axial rotor photo: Dresser Rand
51

• Larger oil and gas
installations use
centrifugal compressors
with 3-10 radial wheels,
6,000–20,000 rpm
(highest for small size), up
to 80 MW load at
discharge pressure of up
to 50 bars and inlet
volumes of up to 500,000
m 3 /hour. Pressure
differential up to 10.
Photo: Dresser Rand
Most compressors will not
cover the full pressure range
efficiently. The lowest pressure is atmospheric, for gas to pipeline, some 3 to
5 MPa (30-50 bar) pressure is used, while reservoir reinjection of gas will
typically require 20 MPa (200 bar) and upwards, since there is no liquid in
the tubing and the full reservoir pressure must be overcome. Therefore,
compression is divided into several stages to improve maintenance and
availability.
Also due to single unit power limitations, compression is often divided in
several parallel trains. This is not the case in this example, since gas is not
exported and reinjection can be interrupted during maintenance periods.
Compressors are driven by gas turbines or electrical motors (for lower power
also reciprocating engines, steam turbines are sometimes used if thermal
energy is available). Often, several stages in the same train are driven by the
same motor or turbine.The main operating parameters for a compressor are
the flow and pressure differentials. The product defines the total loading, so
there is a ceiling set by the maximum design power. Furthermore, there is a
maximum differential pressure (Max P d ) and choke flow (Max Q), the
maximum flow that can be achieved. At lower flow, there is a minimum
pressure differential and flow before the compressor will "surge" if there is
not enough gas to operate.
If variations in flow are expected or differences between common shaft
compressors occur, the situation will be handled with recirculation. A high
flow, high pressure differential surge control valve will open to let gas from
the discharge side back into the suction side. Since this gas is heated, it will
also pass through the heat exchanger and scrubber so as not to become
overheated by circulation.
52

Figure 8. Compressor state diagram
The operating characteristics are defined by the manufacturer. In the
diagram above, the blue lines mark constant speed lines. The maximum
operating limits are set by the orange line as described above. The surge
domain is the area to the left of the red surge curve.
The objective of compressor performance control is to keep the operating
point close to the optimal set point without violating the constraints by means
of control outputs, such as the speed setting. However, gas turbine speed
control response is relatively slow and even electric motors are not fast
enough, since surge response must be in the 100 ms range. Anti-surge
control will protect the compressor from going into surge by operating the
surge control valve. The basic strategy is to use distance between operating
point and surge line to control the valve with a slower response time, starting
at the surge control line. Crossing the surge trip line will cause a fast
response opening of the surge valve to protect the compressor.
Operation with recirculation wastes energy (which could result in
unnecessary emissions) and produces wear and tear, particularly on the
surge valve. Each vendor supplies several variants of compressor control
and anti-surge control to optimize performance, based on various corrective
and predictive algorithms. Some strategies include:
53

• Set point adjustment: If rapid variations in load cause surge valve
action, the set point will be moved to increase the surge margin.
• Equal margin: The set point is adjusted to allow equal margin to
surge between several compressors.
• Model based control: Outside the compressor itself, the main
parameter for the surge margin is the total volume from the surge
valve to the compressor suction inlet, and the response time for the
surge valve flow. A model predictive controller could predict surge
conditions and react faster to real situations while preventing
unnecessary recirculation.
Since compressors require maintenance and are potentially expensive to
replace, several other systems are normally included:
Load management: To balance loading among several compressors in a
train and between trains, the compressor control system
often includes algorithms for load sharing, load shedding
and loading. Compressors are normally purged with inert
gas, such as nitrogen during longer shutdowns, e.g., for
maintenance. Therefore, startup and shutdown sequences
will normally include procedures to introduce and remove
the purge gas.
Vibration:
Vibration is a good indicator of problems in compressors,
and accelerometers are mounted on various parts of the
equipment to be logged and analyzed by a vibration
monitoring system.
Speed governor: If the compressor is turbine driven, a dedicated speed
governor handles the fuel valves and other controls on the
turbine to maintain efficiency and control rotational speed.
For electrical motors this function is handled by a variable
speed drive.
The final function around the compressor itself is lube and seal oil handling.
Most compressors have wet seals, which are traps around shafts where oil
at high pressure prevents gas from leaking out to atmosphere or other parts
of the equipment. Oil is used for lubrication of the high speed bearings. This
oil gradually absorbs gas under pressure and may become contaminated. It
needs to be filtered and degassed. This happens in smaller reboilers, in
much the same way as for the glycol reboilers described earlier.
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4.4 Oil and gas storage, metering and export
The final stage before the oil and gas leaves the platform consists of
storage, pumps and pipeline terminal equipment.
4.4.1 Fiscal metering
Partners, authorities and customers all calculate invoices, taxes and
payments based on the actual product shipped out. Often, custody transfer
also takes place at this point, which means transfer of responsibility or title
from the producer to a customer, shuttle tanker operator or pipeline operator.
Although some small installations are still operated with a dipstick and
manual records, larger installations have analysis and metering equipment.
To make sure readings are accurate, a fixed or movable prover loop for
calibration is also installed. The illustration shows a full liquid hydrocarbon
(oil and condensate) metering system. The analyzer instruments on the left
provide product data such as density, viscosity and water content. Pressure
and temperature compensation is also included.
Figure 9. Metering system
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For liquids, turbine meters with dual pulse outputs are most common.
Alternatives are positive displacement meters (pass a fixed volume per
rotation or stroke) and coriolis mass flow meters. These instruments cannot
cover the full range with sufficient accuracy. Therefore, the metering is split
into several runs, and the number of runs depends on the flow. Each run
employs one meter and several instruments to provide temperature and
pressure correction. Open/close valves allow runs to be selected and control
valves can balance the flow between runs. The instruments and actuators
are monitored and controlled by a flow computer. If the interface is not
digital, dual pulse trains are used to allow direction sensing and fault finding.
To obtain the required accuracy, the meters are calibrated. The most
common method is a prover loop. A prover ball moves though the loop, and
a calibrated volume is provided between the two detectors (Z). When a
meter is to be calibrated, the four-way valve opens to allow oil to flow behind
the ball. The number of pulses from it passes one detector Z to the other and
is counted. After one loop, the four-way valve turns to reverse flow direction
and the ball moves back, providing the same volume in reverse, again
counting the pulses. From the known reference volume, number of pulses,
pressure and temperature the flow computer can calculate the meter factor
and provide accurate flow measurements using formulas from industry
standard organizations such as API MPMS and ISO 5024. The accuracy is
typically ± 0.3% of standard volume.
Gas metering is similar, but instead,
analyzers will measure hydrocarbon
content and energy value (MJ/scm or
BTU, Kcal/scf) as well as pressure
and temperature. The meters are
normally orifice meters or ultrasonic
meters. Orifice plates with a diameter
less than the pipe are mounted in
cassettes. The pressure differential
over the orifice plate as well as
pressure and temperature, is used in
standard formulas (such as AGA 3
and ISO 5024/5167) to calculate normalized flow. Different ranges are
accommodated with different size restrictions.
Orifice plates are sensitive to a buildup of residue and affect the edges of the
hole. Larger new installations therefore prefer ultrasonic gas meters that
work by sending multiple ultrasonic beams across the path and measure the
Doppler effect.
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Gas metering is less accurate than liquid, typically ±1.0% of mass. There is
usually no prover loop, the instruments and orifice plates are calibrated in
separate equipment instead.
LNG is often metered
with mass flow meters
that can operate at the
required low temperature.
A three run LNG
metering skid is shown
above.
At various points in the
movement of oil and gas,
similar measurements
are taken, usually in a
more simplified way.
Examples of different gas
types are flare gas, fuel
gas and injected gas, where required accuracy is 2-5% percent.
4.4.2 Storage
On most production
sites, oil and gas are
piped directly to a
refinery or tanker
terminal. Gas is
difficult to store
locally,
but
occasionally
underground mines,
caverns or salt
deposits can be used
to store gas.
On platforms without
a pipeline, oil is stored in onboard storage tanks to be transported by shuttle
tanker. The oil is stored in storage cells around the shafts on concrete
platforms, and in tanks on floating units. On some floaters, a separate
storage tanker is used. Ballast handling is very important in both cases to
balance the buoyancy when oil volume varies. For onshore, fixed roof tanks
are used for crude, floating roof for condensate. Rock caves are also used
for storage
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Special tank gauging systems such as level radars, pressure or float are
used to measure the level in storage tanks, cells and caves. The level
measurement is converted to volume via tank strapping tables (depending
on tank geometry) and compensated for temperature to provide standard
volume. Float gauges can also calculate density, and so mass can be
established.
A tank farm consists of 10-100 tanks of varying volume for a typical total
capacity in the area of 1-50 million barrels. Storage or shuttle tankers
normally store up to two weeks of production, one week for normal cycle and
one extra week for delays, e.g., bad weather. This can amount to several
million barrels.
Accurate records of volumes and history are kept to document what is
received and dispatched. For installations that serve multiple production
sites, different qualities and product blending must also be handled. Another
planning task is forecasting for future received and delivered products. This
is for stock control and warehousing requirements. A tank farm management
system keeps track of all stock movements and logs all transport operations
that take place.
4.4.3 Marine loading
Loading systems consist of one or
more loading arms/jetties, pumps,
valves and a metering system.
Tanker loading systems are complex,
both because of the volume involved,
and because several loading arms will
normally interact with the tanker's
ballast system to control the loading
operation. The tanks must be filled in
a certain sequence; otherwise the
tanker's structure might be damaged
due to uneven stresses. It is the
responsibility of the tanker's ballast
system to signal data to the loading
system and to operate the different
valves and monitor the tanks on
board the ship. Photo: Statoil
58

5 Midstream facilities
Raw natural gas from the well consists of methane as well as many other
smaller fractions of heavier hydrocarbons, and various other components.
The gas has to be separated into marketable fractions and treated to trade
specifications and to protect equipment from contaminants.
5.1 Gathering
Many upstream facilities include the gathering system in the processing
plant. However, for distributed gas production systems with many (often
small) producers, there is little processing at each location and gas
production from thousands of wells over an area instead feed into a
distributed gathering system. This system in general is composed of:
• Flowlines: A line connecting the wellpad with a field gathering station
(FGS), in general equipped with a fixed or mobile type pig launcher.
• FGS is a system allowing gathering of several flowlines and permits
transmission of the combined stream to the central processing facility
(CPF) and measures the oil/water/gas ratio. Each FGS is composed of:
o Pig receiver (fixed/mobile)
o Production header where all flowlines are connected
o Test header where a single flow line is routed for analysis
purposes (GOR Gas to oil ratio, water cut)
o Test system (mainly test separator or multiphase flow meter)
o Pig trap launcher
• Trunk line – pipeline connecting the FGS with the CPF. Equipped with a
pig receiver at the end.
5.2 Gas plants
5.2.1 Gas composition
When gas is exported, many gas trains include additional equipment for
further gas processing to remove unwanted components such as hydrogen
sulfide and carbon dioxide. These gases are called acids and
sweetening/acid removal is the process of removing them.
Natural gas sweetening methods include absorption processes, cryogenic
processes, adsorption processes (PSA, TSA and iron sponge) and
membranes. Often hybrid combinations are used, such as cryogenic and
membranes.
59

Gas treatment may also include calibration. If the delivery specification is for
a specific calorific value (BTU per scf or MJ per scm), gas with higher values
can be adjusted by adding an inert gas, such as nitrogen. This is often done
at a common point such as a pipeline gathering system or a pipeline onshore
terminal.
Raw natural gas from the well consists of methane as well, as many other
smaller fractions of heavier hydrocarbons and various other components.
Component Chemical
Formula
Boiling Point
at 101 kPa
Vapor pressure
at 20 °C approx.
Methane CH 4 -161,6 °C T cri t −82.6 °C
@ 4,6 MPa
Ethane C 2 H 6 -88.6 °C 4200 kPa
Propane C 3 H 8 -42.1 °C 890 kPa
Butane n-C 4 H 10 −0.5 °C 210 kPa
Higher order HC
Alkenes
Aromatics
Acid gases
Carbon dioxide
Hydrogen sulfide
Mercaptans ex.
Methanethiol
Ethanethiol
Other Gases
Nitrogen
Helium
C n H 2n
e.g. C 6 H 6
CO 2
H 2 S
CH 3 SH
C 2 H 5 SH
N 2
60
−78 °C
-60.2 °C
5.95 °C
35 °C
-195.79 °C
-268.93 °C
5500 kPa
He
Water H2O 0 °C
Trace pollutants
Mercury
Chlorides
Data source: Wikipedia, Air Liquide Gas Encyclopedia
Natural gas is characterized in several ways dependent on the content of
these components:
o Wet gas is raw gas with a methane content of less than 85%.
o
o
Dry gas is raw or treated natural gas that contains less than 15 liters
of condensate per 1,000 SM 3 . (0.1 gallon per 1000 scf).
Sour gas is raw gas with a content of more than 5.7 mg hydrogen
sulfide (H 2 S) per scm (0.25 grains per 100 scf); this is about 4 ppm.

o
o
Acid gas has a high content of acidic gases such as carbon dioxide
(CO 2 ) or H 2 St. Pipeline natural gas specification is typically less than
2% CO 2 . Acid gas fields with up to 90% CO 2 exist, but the normal
range for sour raw gas is 20-40%.
Condensates are a mixture of hydrocarbons and other components
in the above table. These are normally gaseous from the well but
condense out as liquid during the production process (see previous
chapter). This is a refinery and petrochemical feedstock.
Raw gas is processed into various products or fractions:
o
o
o
o
o
Natural gas in its marketable form has been processed for a
specific composition of hydrocarbons, sour and acid components,
etc., and energy content. Content is typically 90% methane, with
10% other light alkenes.
Natural gas liquids (NGL) is a processed purified product
consisting of ethane, propane, butane or some higher alkenes
separately, or in a blend. It is primarily a raw material for
petrochemical industry and is often processed from the condensate.
Liquefied petroleum gas (LPG) refers to propane or butane or a
mixture of these that has been compressed to liquid at room
temperature (200 to 900 kPa depending on composition). LPG is
filled in bottles for consumer domestic use as fuel, and is also used
as aerosol propellant (in spray cans) and refrigerant (e.g., in air
conditioners). Energy to volume ratio is 74% of gasoline.
Liquefied natural gas (LNG) is natural gas that is refrigerated and
liquefied at below -162 °C, for storage and transport. It is stored at
close to atmospheric pressure, typically less than 125 kPa. As a
liquid, LNG takes up 1/600 of the volume of the gas at room
temperature. Energy to volume ratio is 66% of gasoline. After
transport and storage it is reheated/vaporized and compressed for
pipeline transport.
Compressed natural gas (CNG) is natural gas that is compressed
at 2-2,2 MPa to less than 1% of volume at atmospheric pressure.
Unlike higher alkenes, methane cannot be kept liquid by high
pressure at normal ambient temperatures because of a low critical
temperature. CNG is used as a less costly alternative to LNG for
lower capacity and medium distance transport. Methane for vehicle
fuel is also stored as CNG. Energy to volume ratio is typically 25% of
gasoline.
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5.3 Gas processing
Raw natural gas must be processed to meet the trading specifications of
pipeline and gas distribution companies. As part of the purification other
components such as NGL is produced, and pollutants extracted.
The diagram shows an overview of a typical gas plant. Marketable products
are listed in blue and the production process is shown in grey as it is not
considered part of the gas plant.
Figure 10. Typical gas plant
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5.3.1 Acid gas removal
Acid gases such as carbon dioxide and hydrogen sulfide form acids when
reacting with water, and must be removed to prevent corrosive damage to
equipment and pipelines. Hydrogen sulfide is also toxic and total sulfur
content is normally regulated.
The main removal process can be based on several principles:
Absorption allows
acidic gases to be
dissolved in a solvent,
to be released by
regeneration in a later
stage.
Amine
absorption (as shown
on the right) is the most
common process for
acid gas removal.
Monoethanolamine
(MEA) dominates for
CO 2 removal. Solutions
with inorganic solvents
based on ammonia are
under development. Ill:
Wikipedia
A typical amine gas treating process (as shown in the flow diagram) consists
of an absorber unit, a regenerator unit and accessory equipment. In the
absorber, a "lean" amine solution absorbs H2S and CO2 from the upflowing
sour gas to produce a sweetened gas stream as a product. The "rich" amine
solution contains the absorbed acid gases and is routed into the regenerator
(a stripper with a reboiler). The stripped overhead gas from the regenerator
is concentrated H 2 S and CO 2 .
Adsorption relies on the molecules to bind to the surface of certain solids.
After a certain time the material must be regenerated to release the gas.
Principles used include pressure swing adsorption (PSA), temperature swing
adsorption (TSA) and electric swing adsorption (ESA).
Cryogenic removal uses a turbo expander: A gas turbine is driven by the
expanding gas which then cools to below the dew point for the gas to be
removed.
63

The inlet gas to the compressor is precooled by the acid gas removed.
Cryogenic removal is most often used when the content of carbon dioxide is
high, typically around 50%.
Membrane based removal is based on certain materials that allow the acid
gases, but not the hydrocarbons, to diffuse through the membrane. This
procedure can be performed alone or in combination with absorption liquid.
Sulfur Unit. The H2S-rich stripped gas stream is then fed to a Claus
process – a multistage process with two main sections: A thermal section
fires H 2 S with air or oxygen to produce SO 2 and elemental sulfur, which is
released when cooled. A catalytic section allows more H 2 S to react with SO 2
with alumina or titanium dioxide (TiO 2 ) to produce water and elemental sulfur
(the Claus reaction: 2H 2 S + SO 2 → 3S + 2H 2 O). The Claus process can
recover 95-97% of the sulfur in the feed gases.
A tail gas treatment unit serves to reduce the sulfur content to below 250
ppm, corresponding to a total sulfur recovery of 99.9%. More complex
solutions can reduce total sulfur down to 10 ppm. Some important processes
include SCOT (Shell Claus offgas treatment) which removes SO 2 by
combustion with hydrogen over catalysts to produce H 2 S and water. H 2 S is
recycled to the Claus unit. Other solutions are the Beavon sulfur removal
process (BSR), based on amine solvent and catalysts.
5.3.2 Dehydration
Dehydration is either glycol-based scrubbers as described in chapter 4.3.2 or
based on pressure swing adsorption (PSA). Newer processes also use
membranes.
5.3.3 Mercury removal
Mercury removal is generally based on molecular sieves. A molecular sieve
is a substance containing a material with tiny pores to achieve a large
surface area, such as activated carbon. The surface of the material allows
certain molecules to bind by surface tension. The molecules can later be
extracted and the sieve material regenerated by heating, pressure and/or
purging with a carrier gas.
A molecular sieve is commonly cyclic with one active unit and one (or more)
units in regeneration.
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5.3.4 Nitrogen rejection
Excessive nitrogen is removed by cryogenic distillation and higher
concentrations are removed by absorption with lean oil or another special
solvent if a smaller fraction is detected. (See acid gas removal for both
principles). Cryogenic removal also permits production of helium, if present,
as a valuable byproduct.
5.3.5 NGL recovery and treatment
Remaining NGLs are recovered from the gas stream in most modern plants
by a cryogenic turbo expander-based process followed by a fractionating
process. This process leads the cooled NGLs though distillation columns
called de-ethanizer, de-propanizer and de-butanizer, to extract ethane,
propane and butane respectively and leave a residual stream of pentane and
higher hydrocarbons.
The final step is to remove mercaptans (smelly organic gases, e.g., CH 3 SH)
if present, in a sweetening process based on molecular sieves adsorption or
catalytic oxidization such as Merox mercaptan oxidization or Sulfrex, where
the main difference is the type of catalyst.
5.3.6 Sales gas specifications
The exact sales gas specification is specified by pipeline operators and
distributors. Typical standard sales gas requirements use the following
parameters:
Volume is measured in standard cubic meters (scm) defined as 1 m 3 at 0 ºC
and 101.325 kPa or standard cubic feet (scf) as 1 ft 3 at 60 °F (16 °C) and
14.73 PSIA.
Calorific value specifies the total amount of energy per unit generated
during combustion of the gas. The value is used to calculate the amount of
energy delivered. Several values are listed:
• Gross calorific value or gross heat of combustion is the heat
released when a specific quantity of fuel in mixture with air is ignited
and the end products have returned to the initial temperature,
normally 25 ºC. EU specifications are typically 38.8 MJ (10.8 kWh)
±5% per scm. In the US 1030 BTU ±5% per scf.
• Net calorific value or net heat of combustion is the net heat
generated when the water vapor in the gas does not condense
(water forms during combustion) and can be 10% lower.
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Wobbe index measures the heating effect that a burner is exposed to during
combustion. A higher value means a greater thermal load on the burner.
Different gases with the same Wobbe index will impose the same load on
the burner. An excessively high value is a safety hazard, as it can lead to
burner overheating and to excess production of carbon monoxide during
combustion.
Calorific value and Wobbe index can be adjusted by blending gas from
different sources as well as by addition or removal of nitrogen (N 2 ).
Methane number is a value similar to octane value for gasoline, and is
important when the gas is used for internal combustion engines (as CNG).
Hydrogen sulfide and overall sulfur content: Both hydrogen sulfide (H 2 S)
and total sulfur must be reduced. H 2 S is toxic as well as corrosive for the
pipeline, as it forms sulfuric acid (H 2 SO 4 ) and should be kept as low as
possible. Typical maximum values are 5 mg per scm of H 2 S and total sulfur
at 10 mg per scm.
Mercury should be kept below 0.001 ppb (parts-per-billion) which is its
detectable limit. The goal is to limit emissions and to prevent damage to
equipment and pipelines by mercury amalgamation, which makes aluminum
and other metals brittle.
Dew point is a temperature below which some of the hydrocarbons in the
gas can condense at pipeline pressure, forming liquid slugs that can damage
the pipeline. The gas must also be clear of all water vapor to prevent the
formation of methane hydrates within the gas processing plant or within the
sales gas transmission pipeline.
Particles and other substances must be free of particulate solids and all
liquids to prevent erosion, corrosion or other damage to the pipeline and
satisfy limits on carbon dioxide, nitrogen, mercaptans, etc.
Additives: When the natural gas is intended for domestic use,
tetrahydrothiophene (THT) is added so that the otherwise odorless natural
gas can be detected in the event of a gas leak. The sulfurous-smelling
substance added is equal to a sulfur content of 4-7 mg per scm.
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5.4 Pipelines
Pipeline installations consist of driving compressors and pumps, valve
stations, pig receive/launch facilities, where the pig is used for cleaning or
inspecting the pipeline. A pipeline SCADA system and pipeline management
system is required to control and operate the pipeline.
5.4.1 Pipeline terminal
Pipelines transport gas or
liquid, and are fed from the
high pressure compressors or
pumps.
The pipeline terminal includes
termination systems for the
pipeline. A pig launcher and
receiver is a minimum
requirement, allowing insertion
of a pipeline pigging device
used to clean or inspect the
pipeline on the inside. Essentially, it is a large chamber that can be
pressurized and purged to insert and remove the pig or scraper without
depressurizing the pipeline.
The pig is often driven by pipeline flow, either directly or through a pump or
turbine arrangement that also drives wheels that roll against the walls and
mechanisms to rotate brushes and other scraping mechanisms. Intelligent
pigs also contain instrumentation for remote control and cameras, etc.
5.4.2 Gas Pipelines, compressor and valve stations
One or more compressor stations are needed to keep the required gas flow
in the pipeline. Internal friction will cause a pressure drop along the pipeline
that increases with flow. Thus, the starting pressure must be high enough to
maintain design capacity flow up to the final terminal. If this is not practically
possible, additional compressor stations are needed along the total length.
Typical starting pressure is about 150-250 bar (15-25 MPa). The final
pressure can be as low as 50 bar (5 MPa) at the pipeline terminal end.
The compressors are driven in the same way as explained in the
compressor chapter under production (see Chapter 4.3.3).
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As an example, about 150 MW in compressor power is required to transport
70 mill scm/day though the 1166 km Langeled pipeline with a starting
pressure of 250 Ormen Lange Nyhamna. The initial section is 42 in, which
increases to 44 in at Sleipner, a little more than halfway (627 km from
Nyhamna, 540 km from Easington, UK), where the intermediate pressure is
155 bar maximum.
The 1200 km Northstream pipeline from Russia (Portovaya, Vyborg) to
Germany (by Hannover), has two parallel pipes of almost the same
dimensions, pressure and compression power each as Langeled.
Figure 11. Gas pipeline
Block valve stations (or vine valve stations) are required to allow closure of
off flow at regular intervals to limit accidental release of gas in case of
pipeline rupture. This will be determined by the maximum permissible
released gas volume. A valve station is normally operated by remote
telemetry and in addition to the closing valve, at least contains pressure,
temperature and some level of flow measurement. These will feed back into
the pipeline modeling system. Even if methane (CH 4 ) is lighter than air and
will rapidly rise, other gases such as propane (C 3 H 8 ) are present in up to 8%
by volume, and are heavier than air. They will sink, and rapidly create a large
volume of combustible gas mixture.
In cases where multiple producers and pipelines feed into a larger pipeline
grid, the pressure balancing to maintain required flow and observe
contractual volume allocations back to individual production sites presents
additional challenges for the pipeline balancing system.
5.4.3 Liquid pipelines, pump and valve stations
Liquid crude or product pipelines are handled much the same way, with
pump stations and block valve stations along the pipeline. However, when
the pipeline goes up or down over hills and mountains, they behave
differently. Liquid, due to the much higher specific gravity, will experience
much higher pressure drops uphill, and increases downhill, than gas. This
often requires additional pumping capacity uphill and corresponding
68

pressure-reducing turbines (or braking stations) downhill. In case electrical
power is used, the braking power from the turbine can be fed back into the
grid.
Figure 12. Liquid pipeline
Block valve stations (or line valve stations) are used with many of the same
functions as gas pipelines. It is important to limit accidental spills in case of
rupture of the pipeline, and placement will be determined both by maximum
leak volume as well as city, river or valley crossings and wherever it is
particularly important to prevent spills.
5.4.4 Pipeline management, control and safety
Pipeline management is used to maintain operation and integrity of the
pipeline system. It is usually handled by a SCADA system, which interfaces
with remote locations and collects data and controls valves and process
setpoints. The pipeline management system may include functions such as:
Supervisory control to oversee the operation of the entire pipeline system.
Demand Forecasting to model demand for the coming days across the
system based on parameters like contractual volumes, forecasts from
consumers and producers and meteorology to determine necessary supply
rates and corresponding pressures at various points in the network. Since
the transport delay can be considerable during the off-peak season, delays
can be compensated by pre-charging the line in anticipation of increases, or
allowing pressure to be bled off if a reduction is expected.
Pipeline modeling models the entire pipeline system to account for
pressure, temperature and flow at major checkpoints. Based on this model
the management system can perform:
• Pressure balancing to make certain that pressure setpoints are correct to
meet demand forecasts and avoid potential overload conditions.
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• Production allocation, which ensures that producers are able to deliver
their contractual volumes into the network.
• Leak detection, which compares actual measured data against dynamic
data predicted by the model. A discrepancy indicates a leak (or a failing
measurement). Simple liquid systems only calculate basic mass balance
(in-out), while an advanced modeling system can give more precise data
on size and position of the leak within a certain response time.
• Pig or scraper tracking is used to track the position of the pig within the
pipeline, both from pig detection instruments and the pressure drop
caused by the pig in the pipeline.
In case of liquid pipelines transporting batches of different products, a batch
transfer system is needed. Based on information on when each product is
injected into the pipeline, and gravity measurement at the receiving end, it is
possible to sequentially transfer different products, such as gasoline and
diesel in the same pipeline. Depending on product characteristics, there will
be an interface section between the two products that widens as the product
moves along the line. This “off spec” product must be discarded at the
receiving end to avoid product degradation. It is often disposed by mixing
with larger volumes of low grade fuel products. This system is often used
with countrywide refined product distribution to terminals.
Safety systems are used, as for other process plants, to ensure that the
systems shut down in case of malfunctions and out-of-bounds conditions. Of
particular importance is the high integrity pressure protection system
(HIPPS). This is a highly reliable system that is needed to maintain
protection against overpressures, and manage shutdowns. The strategy
used by normal safety system to isolate and depressure, or simply fail to
safe condition, often cannot be applied to pipelines due to the large volumes
of product in the pipelines. Simply opening or closing a valve would
potentially cause overpressure conditions or overload safety devices such as
flares HIPPS monitors and executes these responses in a specific
sequence.
5.5 LNG
LNG is a gas transport product. The gas, which is primarily methane (CH 4 ),
is converted to liquid form for ease of storage or transport, as its volume is
about 1/600th the volume of natural gas in the gaseous state. It is produced
close to the production facilities in an LNG liquefaction plant, stored,
transported in cryogenic tanks on an LNG carrier, and delivered to an LNG
regasification terminal for storage and delivery to a pipeline system.
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LNG carriers are used when the transport distance does not justify the cost
of a pipeline. The main drawback is the cost of the liquefaction, calculated as
how much of the total energy content of the gas is used for liquefaction.
About 6% of energy content is used to produce LNG in a large modern plant,
due to overall thermal efficiency. More than 10% could be consumed with
smaller, gas turbine-driven trains. This compares to losses of about 0.9% per
1,000 km of transport distance for large pipeline systems.
Melkøya LNG Plant with LNG Carrier Arctic Princess Photo: Statoil
The LNG feedstock comes from a gas plant as outlined above. It must
satisfy sales gas specifications. Ethane, propane and butane all have
freezing points of less than -180 °C and can be part of the LNG, but the
concentration of methane is generally above 90%. Some NGLs are also
needed as refrigerant for the cryogenic process.
5.5.1 LNG liquefaction
LNG processes are generally patented by large engineering, oil and gas
companies, but are generally based on a one- two- or three-stage cooling
process with pure or mixed refrigerants. The three main process types of
LNG process with some examples of process licensors are:
• Cascade cycle:
o Separate refrigerant cycles with propane, ethylene and
methane (ConocoPhillips)
• Mixed refrigerant cycle:
o Single mixed refrigerant (SMR) (PRICO)
o Single mixed refrigerant (LIMUM ® ) (Linde)
o Propane pre-cooled mixed refrigerant: C3MR (sometimes
referred to as APCI: Air Products & Chemicals, Inc.)
o Shell dual-mixed process (DMR) (Shell)
71

o Dual mixed refrigerant (Liquefin Axens)
o Mixed fluid cascade process (MFCP) (Statoil/Linde)
• Expander cycle
o Kryopak EXP ® process
Each process has different characteristics in scalability, investment cost and
energy efficiency. For smaller installations, e.g., to handle stranded gas or
isolated small gas fields, a single cycle process is preferable due to its low
CAPEX (and possibly lower weight for floating LNG), even if energy
efficiency is significantly lower than the best cascade or DMR processes,
which cost more but also allow the largest trains typically, 7.8 million tons per
annum and lowest energy consumed per energy unit LNG produced.
Most processes use a mixed refrigerant (MR) design. The reason is that the
gas has a heat load to temperature (Q/T) curve that, if closely matched by
the refrigerant, will improve stability, throughput and efficiency (see the figure
below). The curve tends to show three distinct regions, matching the precooling,
liquefaction and sub-coiling stages. The refrigerant gas composition
will vary based on the individual design, as will the power requirement of
each stage, and is often a patented, location-specific combination of one or
two main components and several smaller, together with careful selection of
the compressed pressure and expanded pressure of the refrigerant, to
match the LNG gas stream.
Figure 13. LNG Q/T diagram
72

Typical LNG train power use is about 28 MW per million tons of LNG per
annum (mtpa), corresponding to typically 200 MW for a large trains of 7.2
mtpa, or 65 MW per stage for three cycles. In addition, other consumers in
gas treatment and pre-compression add to total power consumption and
bring it to some 35-40 MW per mtpa, and over 50 for small LNG facilities well
under 1 mtpa capacity.
Some examples are given here. (Please note that these process flow
diagrams are simplified to illustrate the principle and do not give a complete
design.) All designs are shown with heat exchangers to the sea for
comparison. This is generally needed for high capacity, but for smaller plants
air fin heat exchangers are normally used.
A triple cycle mixed refrigerant cascade claims to have the highest energy
efficiency. It is represented here by the Linde design, co-developed with
Statoil.
Treated
Natural
Gas
Pre Cooling
Liquefaction
Sub Cooling
LNG
G
M
M
M
Figure 14. A triple cycle mixed refrigerant cascade
The actual design varies considerably with the different processes. The most
critical component is the heat exchanger, also called the cold box, which is
designed for optimum cooling efficiency. Designs may use separate cold
boxes, or two or three cycles may combine into one complex common heat
exchanger. This particular deign uses the patented Linde coil wound heat
exchanger, also called the “rocket design,” due to its exterior resemblance to
a classic launch vehicle.
For each train, the cooling medium is first passed through its cooling
compressor. Since pressure times volume over temperature (PV/T) remains
73

constant, it results in a significant temperature rise which has to be
dissipated, typically in a seawater heat exchanger as shown in the figure
above (indicated by the blue wavy line). It then goes though one or more
heat exchangers/cold boxes before it expands, either though a valve or a
turbo-expander, causing the temperature to drop significantly. It is then
returned to cool its cold box before going on to the compressor.
The pre-cooling stage cools the gas to a temperature of about -30 to -50 ºC
in the precooling cold box. The cooling element is generally propane or a
mixture of propane and ethane and small quantities of other gases. The precooling
cold box also cools the cooling medium for the liquefaction and sub
cooling stage.
The liquefaction process takes the gas down from -30 ºC to about -100-125
ºC, typically based on a mixture of methane and ethane and other gases. It
cools the LNG stream as well as the refrigerant for the final stage.
Sub-cooling serves to bring the gas to final stable LNG state at around 162
ºC. The refrigerant is usually methane and/or nitrogen.
The ConocoPhillips optimized cascade process was developed around
1970. It has three cycles with a single refrigerant gas (propane, ethylene and
methane) in each.
Figure 15. Optimized cascade process
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The dual cycle mixed refrigerant (DMR), developed by Shell and others, may
look simpler but the overall design will be similar in complexity as multistage
compressors are typically needed. It is shown on the left with the C3MR on
the right for comparison.
Figure 16. Shell DMR and APLI C3MR designs
For small and micro LNG, single cycle designs are often preferred. There are
literally hundreds of patented solutions, but only a handful of mainline
licensors, that have solved the challenge of achieving single cycle
refrigeration. However, this means multiple internal stages in the process
flow and the heat exchanger itself. The PRICO SMR is shown on the left and
the Linde LIMUM ® (on the right).
Figure 17. PRICO SMR and Linde LIMUM ®
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5.5.2 Storage, transport and regasification
Storage at the terminals and on LNG carriers is done in cryogenic tanks at
atmospheric pressure or slightly above, up to 125 kPa. The tanks are
insulated, but will not keep LNG cold enough to avoid evaporation. Heat
leakage will heat and boil off the LNG. Therefore LNG is stored as a boiling
cryogen, which means that the liquid is stored at its boiling point for its
storage pressure (atmospheric pressure), i.e., about -162 ºC. As the vapor
boils off, heat of vaporization is absorbed from and cools the remaining
liquid. The effect is called auto-refrigeration. With efficient insulation, only a
relatively small amount of boil-off is necessary to maintain temperature. Boiloff
gas from land-based LNG storage tanks is compressed and fed to natural
gas pipeline networks. On LNG carriers, the boil-off gas can be used for fuel.
Gas return line
LNG discharge
line
Compressor
Sea water
T ambient
(10°C ÷ 25°C)
Vaporizer
LNG ship
Recondenser
Gas
pipelines
Discharge sea water
LNG tank
(5°C ÷ 20°C)
Figure 18. LNG terminal process overview
At the receiving
terminal, LNG is
stored in local
cryogenic tanks. It is
regasified to ambient
temperature on
demand, commonly in
a sea water heat
exchanger, and then
injected into the gas
pipeline system.
Cove point LNG terminal
76

6 Refining
Up to the early 1970s, crude oil prices were kept reasonably stable by major
international oil companies and industrialized nations. Less value was
created in the upstream production operations and relatively more profits
were generated in refining and distribution operations. With the 1973 oil
crisis and rising crude oil prices, more of the value was created upstream.
Now, the success of a modern refinery depends more on economies of scale
and the ability to process a wide range of crudes into the maximum quantity
of high value fuels and feedstock. A refinery that is able to handle multiple
types from heavy to light crude is said to have to have a large swing. Trade
specifications such as ”West Texas Intermediate” (WTI) API 38.3°, “Brent
Blend” API 38.3°, “Heavy Arab Crude” API 27.7° or “Grane” API 18.7° are
examples of such crudes.
Medium light crudes can be used directly in early engines and burners.
Modern consumers, such as gas and diesel engines, aviation turbojet
engines and ship bunkers need fuels manufactured to precise specifications.
This includes removing contaminants and pollutants, such as sulfur.
6.1 Fractional distillation
The basic refinery uses fractional distillation. Incoming crude is heated to its
boiling point. It then enters the distillation column, which separates the
different fractions. The column is of the reflux type, where colder condensed
fluids running down are reheated by rising vapors that in turn condense. This
produces clear thermal zones where the different products can be drained.
NOTE: The schematic on the following page is simplified. Both continuous
and vacuum distillation is used in separate columns to avoid heating the raw
crude to more than 370 °C. Overheating would cause thermal cracking and
excessive coke that may also plug pipes and vessels. Also a sidecut stripper
is used, in addition to the main column, to further improve separation.
Sidecut is another name for the fractions emerging from the side (rather than
top and bottom) of the main column, i.e., naphtha, gasoline, kerosene and
diesel.
The fractions are a mix of alkanes and aromatics and other hydrocarbons, so
there is not a linear and uniformly rising relationship between carbon number
and boiling point and density, although there is a rough fit. Even so, this
means that each fraction contains a distribution of carbon numbers and
hydrocarbons.
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6.2 Basic products
The basic products from fractional distillation are:
Figure 19. Fractionating continuous distillation, overview
Liquid petroleum gas (LPG) has carbon numbers of 1-5 and a boiling point
up to 20 °C. Most of the LPGs are propane and butane, with carbon number
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3 and 4 and boiling points -42 °C and -1 °C, respectively. Typical usage is
domestic and camping gas, LPG vehicles and petrochemical feedstock.
Naphtha, or full range naphtha, is the fraction with boiling points between
30 °C and 200 °C and molecules generally having carbon numbers 5 to 12.
The fraction is typically 15–30% of crude oil by weight. It is used mainly as a
feedstock for other processes:
• In the refinery for producing additives for high octane gasoline
• A diluent for transporting very heavy crude
• Feedstock to the petrochemical olefins chain
• Feedstock for many other chemicals
• As a solvent in cleaning
Gasoline has carbon numbers mainly between 4 and 12 and boiling points
up to 120 °C. Its main use is as fuel for internal combustion engines. Early
on, this fraction could be sold directly as gasoline for cars, but today’s
engines require more precisely formulated fuel, so less than 20% of
gasoline at the pump is the raw gasoline fraction. Additional sources are
needed to meet the demand, and additives are required to control such
parameters as octane rating and volatility. Also, other sources such as
bioethanol may be added, up to about 5%.
Kerosene has main carbon numbers 10 to 16 (range 6 to 16) boiling
between 150 °C and 275 °C. Its main use is as aviation fuel, where the best
known blend is Jet A-1. Kerosene is also used for lighting (paraffin lamps)
and heating.
Diesel oil, or petrodiesel, is used for diesel engines in cars, trucks, ships,
trains and utility machinery. It has a carbon number range of 8 to 21 (mainly
16-20) and is the fraction that boils between 200 °C and 350 °C.
White and black oils: The above products are often called white oils, and
the fractions are generally available from the atmospheric distillation
column. The remaining fraction below are the black oils, which must be
further separated by vacuum distillation due to the temperature restriction of
heating raw crude to no more than 370-380 °C. This allows the lighter
fractions to boil off at a lower temperatures than with atmospheric
distillation, avoiding overheating.
Lubricating oils, or mineral base lubricating oil (as opposed to synthetic
lubricants), form the basis for lubricating waxes and polishes. These
typically contain 90% raw material with carbon numbers from 20 to 50 and a
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fraction boiling at 300-600 °C. 10% additives are used to control lubricant
properties, such as viscosity.
Fuel oils is a common term encompassing a wide range of fuels that also
includes forms of kerosene and diesel, as well as the heavy fuel oil and
bunker that is produced at the low end of the column before bitumen and
coke residues. Fuel oil is graded on a scale of 1 to 6 where grade 1 and 2 is
similar to kerosene and diesel, 3 is rarely used anymore. 4-6 are the heavy
fuels, also called Bunker A, B and C, where B and C are very high viscosity
at normal ambient temperatures and requires preheating to about 100 °C
and 120 °C respectively, before it flows enough to be used in an engine or
burner. Fuel oil grade 4 does not require preheating and is sometimes mixed
with off spec products, such as tank residue and interface liquid from
multiphase pipelines or with grade 2 fuel oil to achieve low-enough viscosity
at ambient temperatures. Fuel oil 6 is the lowest grade, its specification also
allows 2% water and 0.5% mineral soil and is consumed almost exclusively
by large ships in international waters, where pollutants such as sulfur is less
regulated.
Bitumen and other residues like coke and tar has carbon numbers above 70
and boiling points above 525 °C. Low sulfur coke can be used for anodes in
the metals industry (aluminum and steel) after processing (calcining). The
remainder is a problem fuel, because of high sulfur content and even higher
CO 2 emissions than coal (typically 15% higher). Bitumen in the form of
asphalt boiling above 525 °C is used for roofing and road paving. Asphalt
concrete pavement material is commonly composed of 5% asphalt/bitumen
and 95% stone, sand, and gravel (aggregates).
6.3 Upgrading and advanced processes
The Refinery make up differs from an upstream plant, in that the overall site
is divided up in to process types or 'units'. The refining plant type processes
are generally licensed, and a license is required to build and operate one of
these. Each license will be the same but scaled to meet the processing
capacity in tons per day. A full explanation of these processes is beyond the
scope of this book, but a non-exhaustive description is given below.
The following figure gives a more detailed process flow diagram of an actual
modern refinery. It shows the extent of treatment that takes place after initial
fractional distillation, to improve fuel yield and functional properties, and an
explanation of why modern gasoline at the pump contains less than 20% raw
gasoline straight from the column. Additional processes may also be
included, e.g., for crude pre-treatment to be able to source lower quality
crudes with less processing at the production site.
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Figure 20. Refinery process flow diagram (Source: Wikipedia)
Most of these reactions take place at elevated temperature and pressure
over a catalyst such as platinum or rhenium or sometimes iron, and need
precise control for optimal throughput. A few process flow diagrams have
been included to give an indication of the complexity of these processes
compared to the relative simplicity of many upstream processes.
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Atmospheric distillation is the fractional distillation unit already described. In
actual designs, it is combined with vacuum distillation. Raw crude cannot be
heated to more than 370-380 °C. It is often called the Crude Oil Distillation
Unit (CDU)
Vacuum distillation unit (VDU) further distills the black oils into fuel oils and
residual bitumen and coke to avoid overheating the crude and to extract
additional valuable product that could be upgraded.
Naphtha hydrotreater: Various sulfur compounds are present in the
hydrocarbon mixture and, if burnt with the other carbons, will cause sulfuric
emissions. The hydrotreater uses hydrogen to remove some of these
compounds. As an example, the hydrodesulfurization (HDS) reaction for
ethanethiol can be expressed as:
ethanethiol + hydrogen → ethane + hydrogen sulfide
C 2 H 5 SH + H 2 → C 2 H 6 + H 2 S
A catalytic reformer unit is used to convert the naphtha molecules (C5-C12)
into higher octane reformate (reformer product). These are mixed with raw
gasoline to achieve a higher octane product. The process creates more
aromatics (ring formed hydrocarbons) by dehydrocyclization or more
complex hydrocarbons with double bonds or side groups by
dehydrogenation. These processes release hydrogen which is recovered
and can be reused in hydrotreaters or hydrocrackers.
Figure 21. Catalytic reformer (Source: Wikipedia)
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Distillate hydrotreater units desulfurize distillates (such as diesel) after
fractional distillation, in the same way as the naphtha hydrotreater.
Fluid catalytic crackers (FCC) units upgrade heavier fractions into lighter,
more valuable products. Long chain molecules (high carbon numbers) are
split into shorter molecules to achieve more of the high value fuel
components. A typical design uses a reactor and a regenerator. A fine
powdered porous catalyst with zeolite (silicate and alumina) is fluidized in the
hydrocarbon vapor, where a reaction takes place at 535 °C and 0.172 MPa.
The catalytic reaction takes place within a few seconds, after which the
reformate and catalyst is separated in a cyclone. The spent catalyst then
goes back to a regenerator that heats it to 715 °C at 0.241 MPa and
releases flue gas. The catalyst powder can then be reused. The reformates
go to a distillation column for separation into fractions.
A hydrocracker unit performs essentially the same function as the FCC when
more saturated hydrocarbons are desirable in the product. This means
alkane carbon chains with single bonds, not double bonds or cyclic rings like
aromatics, or more complex molecules. For this, additional hydrogen is
needed. The reaction takes place with hydrogen under pressure over a
catalyst. The relative market need for diesel, kerosene and gasoline will
influence the choice of FCC versus hydrocracker. In the US, with a higher
relative volume of gasoline, more FCC capacity is needed, while in Europe
and Asia, with higher diesel consumption, more hydrocracking is used.
Visbreaking units upgrade heavy residual oils by thermally cracking them
into lower viscosity product that can be blended into lighter, more valuable
products. Visbreaking is characterized by its thermal severity, ranging from
mild cracking at 425 °C to severe cracking at 500 °C. Depending on the
residual oil, as much as 15-25% lighter fractions like diesel, kerosene and
gasoline could be obtained. The residue is tar and coke.
The Merox unit treats LPG, kerosene or jet fuel by oxidizing thiols
(mercaptans) to organic disulfides. The purpose is to reduce strong odors
caused by thiol presence.
Coking units (delayed coking, fluid coker, and flexicoker), like the visbreaker,
uses thermal cracking of very heavy residual oils into gasoline and diesel
fuel. The residue is green coke, and is further processed to fuel coke or, if
too low in sulfur and contaminants, to anode coke for the metallurgic
industries.
An alkylation unit produces high-octane components for gasoline blending.
The main use is to convert isobutane (C 4 H 10, but arranged differently than n-
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utane) to alkylates, mainly isooctane or isoheptane by adding an alkyl
group such as propene or butene over a strong acid catalyst, such as
sulfuric or hydrofluoric acid.
Dimerization is similar to alkylation, but uses a dimer group instead of an
alkyl group. For example, butenes can be dimerized into isooctene, which
may be hydrogenated to form isooctane.
Isomerization units convert linear molecules to higher-octane branched
molecules by rearranging the same atoms arranged in a different way. For
example, C 4 H 10 n-butane has the carbon atoms in a chain, while isobutane
has a central carbon with one hydrogen and three CH 3 groups attached. The
isobutane can then be fed to the alkylation unit.
Steam reforming produces hydrogen for the hydrotreaters or hydrocracker.
Typical is the steam methane reformer (SMR), where steam reacts with
Methane at 425 °C with a nickel catalyst to produce syngas, which is a
source for many different reactions:
CH 4 + H 2 O ↔ CO + 3 H 2
If more hydrogen is needed, followed by a gas shift reaction with CO:
CO + H 2 O ↔ CO 2 + H 2
Amine gas treater, Claus unit, and tail gas treatment converts hydrogen
sulfide from hydrodesulfurization into elemental sulfur, which is a valuable
traded product.
Figure 22. Claus process (Source: Wikipedia)
The Claus process is the most common with the overall reaction:
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2 H 2 S + O 2 → S 2 + 2 H 2 O
The reactor runs at 1,000° C and 0.15 MPa, with three steps: one thermal
and two catalytic to improve yield.
Using these processes, a modern refinery can raise the basic gasoline yield
depending on crude quality from 10-40% to around to 70%.
6.4 Blending and distribution
After the refining processes, the various fractions are stored in intermediate
tanks, then blended into marketable products for loading onto railcars, trucks
or ships, and distribution to gas stations or industries.
Each product is blended to a specification of up to 25 parameters such as
octane rating, energy content, volatility and sulfur content. The task is to
achieve the specification (and not exceed, where applicable) with the
minimum amount of over-spec “giveaway.” The blending quality is managed
with infrared or chromatograph type process analyzers. These can
determine the precise fractions of a sample by molecule type.
The standard specification gasoline is therefore standard from company to
company in the individual markets, ensuring compatibility with vehicle
manufacturer requirements. Also, the terminal operator may be an
independent third party or run as co-distribution, so that a terminal in one
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egion distributes for several companies based on the same products in the
same tanks.
Each company
then seeks to
differentiate its
product by adding
small quantities of
unique additives
that are marketed
to increase engine
performance,
lifetime, clean
combustion and so
forth. These
additives are
added as the
product is
dispensed to trucks
for delivery to that brand gasoline station.
A main task is to ensure the balance of incoming and outgoing products and
consolidate with stored volumes. These have to be compensated for
temperature, water content (water may be absorbed from air humidity and
released at low temperatures as bottom slop in tanks) and vapor loss. Vapor
or volatile organic compounds (VOCs), form above the product in fixed roof
tanks and when filling up compartments in cars or vessels. VOC loss can be
significant for high volatility products like gasoline, and must be recovered
and/or handled to reduce emissions and explosive hazard.
The terminal management system tracks batches of product received or
dispensed, as well as those eventually received by gasoline stations, airports
or other consumers and consolidates with stored volumes. Each operation
should be validated against orders, bills of lading and positive identification
of trucks, vessels and their operators. In countries where this process is not
well managed, losses of product due to theft and other factors can be as
high as 15% or more in the distribution operations.
Eventually the main goal is to ensure that orders are met, and stakeholders
pay or get paid in the form of VAT, taxes, product, delivery charges, etc.
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7 Petrochemical
Petrochemicals are chemicals made from petroleum or natural gas. Primary
petrochemicals are divided into three groups, depending on their chemical
structure:
Olefins include ethylene, propylene, and butadiene. Ethylene and propylene
are important sources of industrial chemicals and plastics products.
Butadiene is used in making synthetic rubber. Olefins are produced by
cracking.
Aromatic petrochemicals include benzene, toluene, and xylenes. Benzene
is used in the manufacture of dyes and synthetic detergents. Toluene is used
in making explosives. Manufacturers use xylenes in making plastics and
synthetic fibers. Aromatics are produced by reforming.
Synthesis gas (SynGas) is a mixture of carbon monoxide and hydrogen,
and is used to make the petrochemicals ammonia and methanol. Ammonia
is used in making fertilizers and explosives, where methanol serves as a
source for other chemicals.
Figure 23. Petrochemical tree: feedstock and primary petrochemicals
The primary petrochemicals are not end products, but form building blocks
for a wide range of materials. Therefore, each primary petrochemical gives
name to a chain of reactions leading to those materials. There are almost
200 petrochemicals that can be described this way. There are more
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processes than end products, as each product may require multiple steps,
so an exhaustive list would not fit within this book. Instead, we will focus on
the main chains, properties and uses of the most important compounds and
a few key processes for this overview.
Many of these processes are based on polymerization, which means that it
is based on processes that first form monomers then let these bind together
to form polymers as long chains or a three dimensional network. Compounds
whose names start with “poly” are generally polymers, but many other trade
names, such as nylon which is a generic name for a family of polyamides,
are polymers.
Petrochemicals are often made in clusters of plants in the same area. These
plants are often operated by separate companies, and this concept is known
as integrated manufacturing. Groups of related materials are often used in
adjacent manufacturing plants, to use common infrastructure and minimize
transport.
WST - Exxon Singapore Petrochemical Complex
7.1 Aromatics
Aromatics, so called because of their distinctive perfumed smell, are a group
of hydrocarbons that include benzene, toluene and the xylenes. These are
basic chemicals used as starting materials for a wide range of consumer
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products. Almost all aromatics come from crude oil, although small quantities
are made from coal.
7.1.1 Xylene and polyester chain
Figure 24. Aromatics – xylene and polyester chain, derivatives
One of the forms of xylene, paraxylene, is used to make polyesters which
have applications in clothing, packaging and plastic bottles.
The most widely-used polyester is polyethylene terephthalate (PET), used in
lightweight, recyclable soft drink bottles (30% of production), as fibers in
clothing (60% of production), as a filling for anoraks and duvets, in car tire
cords and conveyor belts. It can also be made into a film that is used in
video and audiotapes and X-ray films. Polyester makes up about 18% of
world polymer production and is the third most-produced polymer;
polyethylene (PE) and polypropylene (PP) are first and second, respectively.
Metaxylene is an isomer of mixed xylene. It is used as an intermediate in the
manufacture of polyesters for coatings, inks, reinforced plastics and
packaging applications.
Unsaturated polyester is used over a broad spread of industries, mainly the
construction, boat building, automotive and electrical industries. In most
applications, they are reinforced with small glass fibers. Hence, these
plastics are commonly referred to as glass reinforced plastics (GRP).
Initially a liquid, the resin becomes solid by cross-linking chains. A curative
or hardener creates free radicals at unsaturated bonds, which propagate in a
89

chain reaction to adjacent molecules, linking them in the process. Styrene is
often used to lower viscosity and evaporates during hardening, where the
cross linking releases heat.
Orthoxylene is an isomer of mixed xylene. It is primarily used in plasticizers
(primarily in flexible polyvinyl chloride (PVC) material to make it more
flexible), medicines and dyes.
Alkyd resins are a group of sticky synthetic resins used in protective coatings
and paints.
7.1.2 Toluene, benzene, polyurethane and phenolic
chain
Figure 25, Aromatics – toluene and benzene, polyurethane and
phenolic chain
Tolune diisocyanate (TDI) is an isocyanate used in the production of
polyurethanes for flexible foam applications, ranging from furniture, bedding,
and carpet underlay to transportation and packaging. TDI is also used in the
manufacture of coatings, sealants, adhesives and elastomers.
Nylon is a generic designation for a family of synthetic polymers known
generically as aliphatic polyamides derived from benzene, first produced in
1935 by DuPont. Nylon can be used to form fibers, filaments, bristles, or
sheets to be manufactured into yarn, fabric, and cordage; and it can be
90

formed into molded products. Nylon is tough, elastic and strong, and it has
high resistance to wear, heat, and chemicals. It is generally used in the form
of fine filaments in such articles as hosiery and sports equipment, e.g.,
parachutes; but its applications also include engineering plastics for cars,
toys, healthcare products, carpets, roller-blade wheels and ship sails.
There are many varieties of nylon that have their own characteristic
properties. Nylon plastics are used for making such products as combs,
brushes and gears. Nylon yarns, on the other hand, are used for making
nylon fabrics. When talking about nylon textile, there are two types that are
mostly prevalent in the market: nylon 6-6 (also written as nylon 6,6) and
nylon 6.
Phenol is an aromatic alcohol, mainly used as an intermediate in organic
synthesis. Essentially, it serves as a raw material for the production of
bisphenol A, phenolic resins, alkylphenols and caprolactam. It is a
poisonous, acidic compound obtained from coal tar or benzene and used
mainly as a disinfectant or antiseptic, carbolic acid; any hydroxyl derivative of
benzene.
Phenolic resins are manufactured from phenol. They are used in wood
products and molding powders applications, and also have a wide range of
applications on the electrical, mechanical and decorative markets, in the
automotive industry, in building and construction, in thermal insulation
products and in foundry industry products.
Epoxy resin is a flexible resin made using phenols and used chiefly in
coatings, adhesives, electrical laminants and composites for its excellent
adhesion, strength and chemical resistance.
Polycarbonates are a particular group of thermoplastics. They are easily
worked, molded, and thermoformed; as such, these plastics are very widely
used in modern manufacturing. Polycarbonate is becoming more common in
housewares, as well as laboratories and in industry. It is often used to create
protective features, for example, in banks as well as vandal-proof windows
and lighting lenses for many buildings.
7.1.3 Benzene and styrenic chain, derivatives
Polystyrene is solid plastic made from polymerized styrene. It is the second
most common plastic and used in a wide variety of everyday applications,
from coffee cups to CD jewel boxes. It is a thermoplastic polymer in a solid
“glassy” state at room temperature, but flows if heated above about 100 °C.
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It becomes solid again when cooled. This allows polystyrene to be extruded,
molded and vacuum-formed in molds with fine detail and high finish.
Figure 26. Aromatics – benzene and styrenic chain, derivatives
Styrene-acrylonitrile (SAN) is like polystyrene but offers higher thermal
resistance and is therefore used mainly in the automotive, electrical and
electronics industry, as well as in household applications and building
products.
Acrylonitrile-butadiene-styrene (ABS) is a tough, heat-resistant and impactresistant
thermoplastic, with the acrylonitrile providing heat resistance and
the styrene units offering rigidity. It is widely used for appliance and
telephone housings, luggage, sporting helmets, pipe fittings and automotive
parts.
Styrene-butadiene rubber (SBR) is a rubber manufactured from styrene.
Because of its excellent abrasion resistance, it is widely used in automobile
and truck tires, as well as for carpet backing and paper coating. About 50%
of a car tire is made from SBR. Other applications are in belting, flooring,
wire and cable insulation and footwear.
7.2 Olefins
Olefins are petrochemical derivatives produced by cracking feed stocks from
raw materials such as natural gas and crude oil. Lower olefins have short
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chains with only two, three or four carbon atoms, and the simplest one is
ethylene. The higher olefins have chains of up to twenty or more carbon
atoms. The main olefin products are ethylene, propylene, butadiene and C4
derivatives. They are used to produce plastics, as chemical intermediates,
and, in some cases, as industrial solvents.
7.2.1 Ethylene, derivatives
Figure 27. Olefins – ethylene, derivatives
Polyester and polyester resins is described under the Aromatics chain
(Chapter 7.1.1).
Ethanol, also known as ethyl alcohol (common alcohol), is manufactured by
synthesis from ethylene. It is an oxygenated hydrocarbon used in a wide
variety of high performance solvent applications (toiletries and cosmetics,
paints, lacquer thinners, printing inks, dyes, detergents, disinfectants and
pharmaceuticals), as a chemical raw material for the production of a range of
monomers and solvents, and is essential in pharmaceutical purification. In
transportation, ethanol is used as a vehicle fuel by itself, blended with
gasoline, or as a gasoline octane enhancer and oxygenate.
Ethanolamines are prepared by the reaction of ammonia and ethylene oxide.
They include monoethanolamine (MEA), diethanolamine (DEA) and
triethanolamine (TEA). The three are widely used in industry, principally as
absorbents for acidic components of natural gas and of petroleum-refinery
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gas streams. It is also used to make detergents, metalworking fluids, and as
gas sweetening. TEA is used in detergents and cosmetics applications and
as a cement additive.
Polyethylene (PE), with a world production around 80 million tons, is the
most common plastic (and polymer). It is a polymer of ethylene, especially
any of various lightweight thermoplastics that are resistant to chemicals and
moisture, and has good insulating properties. Its primary use is in packaging
(plastic bags, plastic films, geomembranes, containers including bottles,
etc.).
Many kinds of polyethylene are known, with most having the chemical
formula (C 2 H 4 ) n H 2 . It has many different trade varieties, and the most
common are:
High-density polyethylene (HDPE) is used predominantly in the
manufacture of blow-molded bottles for milk and household cleaners
and injection-molded pails, bottle caps, appliance housings and toys.
Low-density polyethylene (LDPE) is used in film applications due
to its toughness, flexibility and relative transparency. Typically,
LDPE is used to manufacture flexible films such as those used for
plastic retail bags. LDPE is also used to flexible lids and bottles, in
wire and cable applications for its stable electrical properties and
processing characteristics.
Linear low-density polyethylene (LLDPE) is used predominantly in
film applications due to its toughness, flexibility and relative
transparency. LLDPE is the preferred resin for injection molding
because of its superior toughness
Polyvinyl chloride (PVC). A polymer of vinyl chloride is used to make a
diverse range of cost-effective products with various levels of technical
performance suited to a wide range of applications. Many of these PVC
products are used every day and include everything from medical devices
such as medical tubing and blood bags, to footwear, electrical cables,
packaging, stationery and toys.
7.2.2 Propylene, derivatives
Polypropylenes (PP) are various thermoplastic plastics or fibers that are
polymers of propylene. Polypropylene can be made into fibers, where it is a
major constituent in fabrics for home furnishings such as upholstery and
carpets. Numerous industrial end uses include rope and cordage, disposable
non-woven fabrics for diapers and medical applications. As a plastic,
polypropylene is molded into bottles for foods and personal care products,
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appliance housings, dishwasher-proof food containers, toys, automobile
battery casings and outdoor furniture.
Polyurethanes are used to make the foam in furniture, mattresses, car
seats, building insulation, and coatings for floors, furniture and refrigerators.
They are also used in artificial sports tracks, jogging shoes, and in roller
blade wheels. (See also, Chapter 7.1.2.)
Figure 28. Olefins – propylene, derivatives
Acrylonitrile-butadiene-styrene (ABS) (see chapter 7.1.3).
Polyacrylonitrile (PAN) is a semi-crystalline polymer resin. Though it is
thermoplastic, it does not melt under normal conditions. It degrades before
melting. It is used to produce large variety of products including ultra-filtration
membranes, hollow fibers for reverse osmosis, fibers for textiles, and PAN
fibers that are the chemical precursor of carbon fiber.
Cumene is an aromatic derived from benzene and is used in turn to produce
polycarbonates, phenolic resins and essential healthcare products such as
aspirin and penicillin.
Methyl methacrylate (MMA). The principal application of methyl
methacrylate is the production of polymethyl methacrylate (PMMA) acrylic
plastics. Also, MMA is used for the production of the co-polymer methyl
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methacrylate butadiene-styrene (MBS), used as a modifier for PVC. MMA
polymers and copolymers are used for waterborne coatings, such latex
house paint.
7.2.3 Butadiene, butylenes, and pygas, derivatives
Pygas, or pyrolysis gasoline, is a naphtha-range product with a high
aromatic content, used either for gasoline blending or as a feedstock for a
BTX extraction unit. Pygas is produced in an ethylene plant that processes
butane, naphtha or gasoil.
Figure 29. Olefins – butadiene, butylene, and pygas, derivatives
Styrene-butadiene (rubber) (SBR) (see Chapter 7.1.3.)
Methyl methacrylate (MMA) (see chapter 7.2.2
Polybutadiene is a synthetic rubber that is a polymer formed from the
polymerization of the monomer 1,3-butadiene. It has a high resistance to
wear and is used especially in the manufacture of tires. It has also been
used to coat or encapsulate electronic assemblies offering extremely high
electrical resistivity.
Polyisobutylene is a synthetic rubber, or elastomer. It is special because it
is the only rubber that is gas impermeable; it is the only rubber which can
hold air for long periods of time. Polyisobutylene, sometimes called butyl
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ubber is a vinyl polymer, and is very similar to polyethylene and
polypropylene in structure.
Polybutylene (PB-1) is a high molecular weight, linear, isotactic, and semicrystalline
polymer. PB-1 replaces materials like metal, rubber and
engineering polymers. Because of its specific properties it is mainly used in
pressure piping, flexible packaging, water heaters, compounding and hot
melt adhesives.
Methyl-tert-butyl-ether (MTBE) is used in gasoline to boost the octane
rating and to decrease toxic emissions in the exhaust. As an octane
enhancer, MTBE delivers high octane numbers at relatively low cost. A direct
effect of the use of MTBE is the reduction of both "regulated" emissions (CO,
unburned hydrocarbons) and "unregulated" emissions.
7.3 Synthesis gas (syngas)
Synthesis gas (syngas) is a mixture of carbon monoxide and hydrogen. It
can be created from coal or methane reacting with steam at high
temperatures:
From coal:
C + H 2 O → H 2 + CO
Or from methane: CH 4 + 1/2O 2 → CO + 2H 2 Lean combustion
CH 4 + H 2 O → CO + 3H 2 Steam reforming
Figure 30. Synthesis gas
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Syngas is used for production of methanol or ammonia. It is also used for
production of synthetic fuels, both diesel (Fischer–Tropsch process) and
gasoline (see Chapter 9.1.5).
7.3.1 Methanol based products
Methanol, a colorless alcohol, is a chemical used in the production of
formaldehyde, acetic acid and methyl methacrylate (MMA), and is used as a
solvent in many applications. It is also used to produce MTBE and other
products, and can be used in fuels.
Melamine resin or melamine formaldehyde (also, incorrectly, melamine) is a
hard, thermosetting plastic material made from melamine and formaldehyde
by polymerization. This plastic is often used in kitchen utensils or plates and
is the main constituent in high pressure laminates and laminate flooring.
Urea-formaldehyde is a non-transparent thermosetting resin or plastic,
made from urea and formaldehyde. It is used in adhesives, finishes, MDF
and molded objects. Its attributes include high tensile strength, heat
distortion temperature, low water absorption, mold shrinkage, high surface
hardness and elongation at break.
Phenol formaldehyde is a low-cost basic resin. Addition of appropriate
fillers can generate high temperature-resistant grades (185 °C/370 °F).
Normal phenolics are resistant to 150 °C/300 °F. Applications include
moldings, bottle tops, resins, chemically resistant coatings for metals,
laminates, water lubricated bearings and foams for thermal insulation.
Polyoxymethylene (POM), also known as acetal resin, polytrioxane,
polyformaldehyde and paraformaldehyde, is an engineering plastic used to
make gears, bushings and other mechanical parts. It is also known in variant
trade names such as Delrin, Celcon and Hostaform. It is the most important
polyacetal resin; a thermoplastic with good physical and processing
properties.
MTBE (see Chapter 7.2.3).
Methyl methacrylate (see Chapter 7.2.2).
Dimethyl terephthalate (DMT) is an ester of terephthalic acid and methanol
and is used in the production of polyesters, including polyethylene
terephthalate and polytrimethylene terephthalate. It consists of benzene with
methyl ester groups attached. DMT has largely been replaced by pure
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terephthalic acid (PTA) as the preferred industrial route to polyester
production.
7.3.2 Ammonia based products
Ammonia is a pungent, colorless, gaseous alkaline compound of nitrogen
and hydrogen (NH 3 ) that is very soluble in water and can easily be
condensed to a liquid by cold and pressure. It is manufactured by the direct
combination of hydrogen and nitrogen under pressure over a catalyst. The
main process is still the Haber-Bosch synthesis invented in 1915, operating
at 15–25 MPa and between 300 and 550 °C in four reaction chambers with
catalyst. Anhydrous ammonia is mainly used for the manufacture of
nitrogenous fertilizers. It is also a building block for the synthesis of many
pharmaceuticals, for explosives, and is used in many commercial cleaning
products.
Urea CO(NH 2 ) 2 is synthesized from ammonia and carbon dioxide. It is
named for its presence in human and most land animal urine (except fish
and birds). Dissolved in water, it is neither acidic nor alkaline. Urea is widely
used in fertilizers as a convenient source of nitrogen. Urea is also an
important raw material for the chemical industry in animal feed, plastics and
resins.
Yara Porsgrunn Ammonia Fertilizer plant
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8 Utility systems
This chapter contains an overview of the various systems that provide
utilities or supports for the main process.
8.1 Process control systems
A process control system is used to monitor data and control equipment on
the plant. Very small installations may use hydraulic or pneumatic control
systems, but larger plants with up to 250,000 signals to and from the process
require a dedicated distributed control system. The purpose of this system is
to read values from a large number of sensors, run programs to monitor the
process and control valves, switches etc. to control the process. Values,
alarms, reports and other information are also presented to the operator and
command inputs accepted.
Typical process control system
Process control systems consist of the following components:
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• Field instrumentation: sensors and switches that sense process
conditions such as temperature, pressure or flow. These are
connected over single and multiple pair electrical cables
(hardwired) or communication bus systems called fieldbus.
• Control devices, such as actuators for valves, electrical switchgear
and drives or indicators are also hardwired or connected over
fieldbus.
• Controllers execute the control algorithms so that the desired actions
can be taken. The controllers also generate events and alarms
based on changes of state and alarm conditions, and prepare data
for operators and information systems.
• A number of servers perform the data processing required for data
presentation, historical archiving, alarm processing and engineering
changes.
• Clients, such as operator stations and engineering stations, are
provided for human interfaces to the control system.
• The communication can be laid out in many different configurations,
often including connections to remote facilities, remote operations
support and other similar environments.
Figure 31. Function blocks define the control
The main function of the control system is to make sure the production,
processing and utility systems operate efficiently within design constraints
and alarm limits. The control system is typically specified in programs as a
combination of logic and control function blocks, such as AND, ADD and
PID. For a particular system, a library of standard solutions such as level
control loops and motor control blocks are defined. This means that the
system can be specified with combinations of typical loop templates,
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consisting of one or more input devices, function blocks and output devices.
This allows much if not all of the application to be defined based on
engineering databases and templates rather than formal programming.
The system is
operated from a
central control
room (CCR) with a
combination of
graphical process
displays, alarm
lists, reports and
historical data
curves. Smaller
personal screens
are often used in
combination with
large wall screens
as shown on the
right. With modern systems, the same information is available to remote
locations such as onshore corporate operations support centers.
Field devices in most process areas must be protected
to prevent them from becoming ignition sources for
potential hydrocarbon leaks. Equipment is explosive
hazard classified, e.g., as safe by pressurization (Ex.p),
safe by explosive proof encapsulation (Ex.d) or
intrinsically safe (Ex.i). All areas are mapped into
explosive hazard zones from Zone 0 (inside vessels
and pipes), Zone 1 (risk of hydrocarbons), Zone 2 (low risk of hydrocarbons)
and Safe Area.
Beyond the basic functionality, the control system can be used for more
advanced control and optimization functions. Some examples are:
• Well control may include automatic startup and shutdown of a well
and/or a set of wells. Applications can include optimization and
stabilization of artificial lift, such as pump off control and gas lift
optimization.
• Flow assurance ensures that the flow from wells and in pipelines and
risers is stable and maximized under varying pressure, flow and
temperatures. Unstable flow can result in slug formation, hydrates,
etc.
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• Optimization of various processes to increase capacity or reduce
energy costs.
• Pipeline management modeling, leak detection and pig tracking.
• Support for remote operations, in which facility data is available to
company specialists located at a central support center.
• Support for remote operations where the entire facility is unmanned
or without local operators full or part time, and is operated from a
remote location.
8.1.1 Safety systems and functional safety
The function of safety systems is to take control and prevent an undesirable
event when the process and the facility are no longer operating within normal
operating conditions. Functional safety is the part of the overall safety of a
system that depends on the correct response of the safety system response
to its inputs, including safe handling of operator errors, hardware failures and
environmental changes (fires, lightning, etc.).
.
The definition of safety is “freedom from unacceptable risk” of physical injury
or of damage to the health of people, either directly or indirectly. It requires a
definition of what is acceptable risk, and who should define acceptable risk
levels. This involves several concepts, including:
1. Identifying what the required safety functions are, meaning that
hazards and safety functions have to be known. A process of
function reviews, formal hazard identification studies (HAZID),
hazard and operability (HAZOP) studies and accident reviews are
applied to identify the risks and failure modes.
2. Assessment of the risk-reduction required by the safety function.
This will involve a safety integrity level (SIL) assessment. A SIL
applies to an end-to-end safety function of the safety-related system,
not just to a component or part of the system.
3. Ensuring the safety function performs to the design intent, including
under conditions of incorrect operator input and failure modes.
Functional safety management defines all technical and
management activities during the lifecycle of the safety system. The
safety lifecycle is a systematic way to ensure that all the necessary
activities to achieve functional safety are carried out, and also to
demonstrate that the activities have been carried out in the right
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order. Safety needs to be documented in order to pass information
to different engineering disciplines.
For the oil and gas industry, safety standards comprise a set of corporate,
national and international laws, guidelines and standards. Some of the
primary international standards are:
• IEC 61508 Functional safety of electrical/electronic/programmable
electronic safety-related systems
• IEC 61511 Functional safety - Safety instrumented systems for the
process industry sector
A safety integrity level is not directly applicable to individual subsystems or
components. It applies to a safety function carried out by the safety
instrumented system (end-to-end: sensor, controller and final element).
IEC 61508 covers all components of the E/E/PE safety-related system,
including field equipment and specific project application logic. All these
subsystems and components, when combined to implement the safety
function (or functions), are required to meet the safety integrity level target of
the relevant functions. Any design using supplied subsystems and
components that are all quoted as suitable for the required safety integrity
level target of the relevant functions will not necessarily comply with the
requirements for that safety integrity level target.
Suppliers of products intended for use in E/E/PE safety-related systems
should provide sufficient information to facilitate a demonstration that the
E/E/PE safety-related system complies with IEC 61508. This often requires
that the functional safety for the system be independently certified.
There is never one single action that leads to a large accident. It is often a
chain of activities. There are many layers to protect against an accident, and
these are grouped two different categories:
• Protection layers – to prevent an incident from happening. Example:
rupture disk, relief valve, dike.
• Mitigation layers – to minimize the consequence of an incident.
Example: Operator intervention or safety instrumented system (SIS)
An SIS is a collection of sensors, controllers and actuators that execute one
or more SIFs/safety loops that are implemented for a common purpose.
Each SIF has its own safety integrity level (SIL) and all sensors, controllers
and final elements in one SIF must comply with the same SIL, i.e., the end-
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to-end safety integrity level. The SIS is typically divided into the following
subsystems:
• Emergency shutdown system (ESD) to handle emergency
conditions (high criticality shutdown levels)
• Process shutdown system (PSD) to handle non-normal but less
critical shutdown levels
• Fire and gas systems to detect fire, gas leakage and initiate
firefighting, shutdown and isolation of ignition sources
The purpose of an SIS is to reduce the risk that a process may become
hazardous to a tolerable level. The SIS does this by decreasing the
frequency of unwanted accidents:
• SIS senses hazardous conditions and takes action to move the
process to a safe state, preventing an accident from occurring.
• The amount of risk reduction that an SIS can provide is represented
by its SIL, which is a measure of the risk reduction factor provided
by a safety function. IEC 61508 defines four levels, SIL 1-4, and the
corresponding requirements for the risk reduction factor (RFF) and
probability of failure on demand (PFD):
SIL PFD RRF
1 0.1 – 0.01 10 – 100
2 0.01 – 0.001 100 – 1000
3 0.001 – 0.0001 1000 – 10.000
4 0.0001 – 0.00001 10.000 – 100.000
The SIL for a component is given by its PFD, safe failure fraction and design
to avoid influence of systematic errors.
8.1.2 Emergency shutdown and process shutdown
The emergency shutdown (ESD) and process shutdown (PSD) systems will
take action when the process goes into a malfunction or dangerous state.
For this purpose, the system maintains four sets of limits for a process value,
LowLow (LL), Low (L), High (H) and HighHigh (HH). L and H are process
warning limits which alert to process disturbances. LL and HH are alarm
conditions and detect that the process is operating out of range and there is
a chance of undesirable events and malfunction.
Separate transmitters are provided for safety systems. One example is the
LTLL (level transmitter LowLow) or LSLL (level switch LowLow) alarm for the
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oil level. When this condition
is triggered, there is a risk of
blow-by, which means gas
leaks out of the oil output and
causes high pressure in the
next separation stage or
other following process
equipment, such as a
desalter. Transmitters are
preferred over switches
because of better diagnostic
capabilities.
Emergency shutdown actions
are defined in a cause-andeffect
chart based on a
HAZOP of the process. This
study identifies possible
malfunctions and how they should be handled. On the left of the chart, we
have possible emergency scenarios. On top, we find possible shutdown
actions. At an oil and gas facility, the primary response is to isolate and
depressurize. In this case, the typical action would be to close the inlet and
outlet sectioning valves (EV 0153 20, EV 0108 20 and EV 0102 20 in the
diagram), and open the blowdown valve (EV 0114 20). This will isolate the
malfunctioning unit and reduce pressure by flaring of the gas.
Events are classified on a
scale, e.g., 0 to 5, where a
full abandon platform/facility
shutdown (APS – ESD 0)
as the highest level means
a complete shutdown and
evacuation of the facility.
The next levels (ESD1,
ESD2), define emergency
complete shutdown. The
lower levels (e.g., PSD 3,
PSD 4 and PSD 5)
represent single equipment
or process section
shutdowns. A split between
APS/ESD and PSD is done
in large installations
because most signals are
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PSD and can be handled with less strict requirements.
These actions are handled by the emergency shut down system (ESD) and
process shut down system (PSD) according to functional safety
requirements and standards. Thus, a typical ESD function might require a
SIL 3 or even SIL 4 level, while PSD loops could be SIL 2 or SIL 3.
Smaller ESD systems, e.g., on wellhead platforms, can be hydraulic or
hardwired (non-programmable).
8.1.3 Fire and gas system
The fire and gas system is not generally
related to any particular process.
Instead, it divides into fire areas by
geographical location. Each fire area
should be designed to be self-contained,
in that it should detect fire and gas by
several types of sensors, and control fire
protection and firefighting devices to
contain and fight fire within the fire area.
In the event of fire, the area will be
partially shut off through closure of
ventilation fire dampers. A fire area
protection data sheet typically shows what detection exists for each fire area,
and which fire protection action should be taken in case of an incident.
The type and number of the detection, protection and fighting devices
depends on the type of equipment and size of the fire area and will vary for
different process areas, e.g., electrical rooms and accommodation rooms.
Fire detection:
• Gas detection: Combustible and toxic gas, electro-catalytic or
optical (IR) detector
• Flame detection: Ultraviolet (UV) or infra red (IR) optical detectors
• Fire detection: Heat and ionic smoke detectors
• Manual pushbuttons
Firefighting, protection:
• Gas-based firefighting, such as CO 2
• Foam-based firefighting
• Water-based firefighting: sprinklers, mist (water spray) and deluge
• Protection: Interface to emergency shutdown and HVAC fire dampers.
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• Warning and escape: PA systems, beacons/lights, fire door and
damper release
A separate package related to fire and gas is the diesel- or electrically-driven
fire water pumps for the sprinkler and deluge ring systems.
For fire detection, coincidence and logic are often used to identify false
alarms. In such schemes, several detectors in the same area are required to
detect a fire condition or gas leakage for automatic reaction. This will include
different detection principles, e.g., a fire, but not welding or lightning strike.
Action is controlled by a fire and
gas system (F&G). Like the ESD
system, F&G action is specified
in a cause and action chart
called the Fire Area Protection
Datasheet. This chart shows all
detectors and fire protection
systems in a fire area and how
the system will operate.
The F&G system often provides
supervisory functions, either in
the F&G or the information
management system (IMS) to
handle such tasks as
maintenance, calibration or
replacement and hot work
permits, e.g., welding. Such
actions may require that one or
more fire and gas detectors or
systems are overridden or
bypassed. Specific work
procedures should be enforced,
such as a placing fire guards on duty, to make sure all devices are reenabled
when the work permit expires or work is complete.
8.1.4 Control and safety configuration
Piping and instrumentation diagrams (P&ID) show the process. Additional
information is needed for the specification of the process control and safety
systems design and their control logic. These include: Loop diagram,
Instrument datasheet, Cable schedule and Termination list.
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P&ID
109

The illustration shows one typical format. This is the common format for the
NORSOK SCD standard. (Example for the Njord Separator 1 and 2 systems
control diagram). Essentially, the P&ID mechanical information has been
removed, and control loops and safety interlocks drawn in with references to
typical loops.
8.1.5 Telemetry/SCADA
Supervisory control and data acquisition (SCADA) is normally associated
with telemetry and wide area communications, for data gathering and control
over large production sites, pipelines, or corporate data from multiple
facilities. With telemetry, the bandwidth is often quite low and based on
telephone or local radio systems. SCADA systems are often optimized for
efficient use of the available bandwidth. Wide area communication operates
with wideband services, such as optical fibers and broadband internet.
Figure 32. SCADA system topology (typical)
Remote terminal units (RTU) or local controls systems on wells, wellhead
platforms, compressor and pump stations, are connected to the SCADA
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system by means of the available communication media. SCADA systems
have many of the same functions as the control system, and the difference
between them is mainly their data architecture and use of communications.
8.2 Digital oilfield
In the oil and gas industry digital oilfield (DOF) is a generic term for new
solutions and technologies for operation, work processes and methods that
are being made possible by adopting innovations in information technology.
Other names such as Integrated Operations (IO), E-Field, Smart Fields, i-
Field and Integrated Asset Management are used for the same concept.
Intelligent Energy is a general umbrella term adopted by Society of
Petroleum Engineers (SPE).
Central to this concept is collaboration between people; where data,
information, knowledge shared between a number of parties in digital form.
This often supported by technologies such as video conferencing and
augmented reality for personnel in remote locations or in the field. In this
environment we add solutions for optimal performance, security,
maintenance.
Figure 33. Digital Oilfield
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Optimal production targets and maximum utilization of production resources
are achieved through the use of several sources of information, such as
reservoir mass balance calculations and depletion strategies, well test
results and use of simulation models. This is made possible by linking skills,
data and tools together in real time – independent of location.
Some of the enabler technology areas are:
1. A system and communication IT infrastructure
2. Applications for remote operations and remote operations support
3. Reservoir management and drilling operations
4. Production optimization
5. Information management systems
6. Operation support and maintenance
8.2.1 Reservoir management and drilling operations
Solution for data acquisition, modeling
and visualization between facility
operators and central company experts
to provide:
• Drilling simulation and
visualization, automatic
diagnostics and decision
support, real-time measurements
while drilling in order to locate the best targets
• Reservoir models based on real-time reservoir data, analysis of 4D
seismic, in-situ measurements of changes. On-line integration with
well-serviced company data
• Optimization models for increased production, based on in-reservoir
properties during production, with decision support incorporated to
improve productivity
8.2.2 Production optimization
Optimizing the production or improving productivity is a complex problem. In
addition to the production optimization of the downhole, subsea and topside
process, one has to consider operational costs, hardware damage, reservoir
performance, environmental requirements and operational difficulties within
each well and/or topside. To further complicate optimization, the individual
challenges will change over time, e.g., reservoir behavior changes as an
effect of depletion, shutdown of wells due to slugging, failed sensors and the
change of efficiencies within the topside process system. Some of the
applications included in production optimization are:
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• Flowline control to stabilize multiphase flow in gathering systems,
risers and flow lines.
• Well control that will stabilize and optimize gas lift and naturally
flowing wells. This application should prevent flow and pressure
surges while maintaining minimal backpressure and maintain
maximum production as well as continuing production at the
optimum lift gas rate.
• Gas-lift optimization is provided to ensure the best possible
distribution of lift-gas between gas lifted wells.
• Slug management helps mitigate variations in inflow impact. The
separation and hydrocarbon processing during startup, upset and
normal operation.
• Well monitoring systems (WMS) are used to estimate the flow rates
of oil, gas and water from all the individual wells in an oil field. The
real-time evaluation is based on data from available sensors in the
wells and flow lines.
• Hydrate prediction tools help to avoid hydrate formation, which may
occur if a subsea gathering system is allowed to cool down too much
before the necessary hydrate preventive actions are performed.
• Optimal operation is defined by a set of constraints in the wells and
production facilities. A constraint monitoring tool monitors the
closeness to all constraints. This provides decision support for
corrective actions needed to move current operation closer to its true
potential.
• Advanced control and optimization solutions to improve the
performance of product quality control, while adhering to operating
constraints. This is typically done with two technologies: model
predictive control to drive the process closer to operating targets,
and inferential measurement to increase the frequency of product
quality feedback information.
• Tuning tools are designed to optimize and properly maintain the
optimal setting of control loops in the process automation system.
8.2.3 Asset optimization and maintenance support
An asset optimization (AO) system reduces costly production disruptions by
enabling predictive maintenance. It records the maintenance history of an
asset and identifies potential problems to avert unscheduled shutdowns,
maximize up-time and operate closer to plant production prognoses. This
functionality supports maintenance workflow as the AO system
communicates with a maintenance system, often denoted as a computerized
maintenance management system (CMMS).
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Messenger
Asset
Condition
Document
ERP-System
CMMS*
Maintenance Management
Create work order
Work order history
Maintenance status
Preventive maintenance,…
Operator
Asset Monitor
Service staff
extern
Diagnosis
and
Status Data
Actuator/
Valve
Heat Exchanger
Maximize the utilization of
plant assets over their lifecycle
Figure 34. Computerized maintenance management system
Condition monitoring includes both structural monitoring and condition
monitoring for process equipment such as valves and rotating machinery.
For structural monitoring, the devices are corrosion meters (essentially
plates that corrode, so that corrosion may be metered), tension force meters
and free swinging strings. These statistics are logged to a central structure
condition monitoring system, to show what forces are acting against the
installation, and the effect those forces are having.
Condition monitoring of machinery is generally used for large rotating
apparatus, such as turbines, compressors, generators and large pumps.
Input devices are vibration meters, temperature (bearing, exhaust gases,
etc.), as well as the number of start/stops, running time, lubrication intervals
and over-current trip-outs. For other process equipment, such as valves, the
system can register closing times, flow and torque. A valve that exhibits a
negative trend in closing time or torque ("stiction") can be diagnosed. The
maintenance trigger is the mechanism whereby field device or equipment
monitor resident information, in the form of digital status signals or other
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numerical or computed variables are interpreted to trigger a maintenance
request. A work order procedure is then automatically initiated in the CMMS.
Maintenance support functionality will plan maintenance, based on input
from condition monitoring systems, and a periodic maintenance plan. This
will allow the system to schedule personnel for such tasks as lubrication or
cleaning, and plan larger tasks such as turbine and compressor periodic
maintenance.
8.2.4 Information management systems (IMS)
A specific information management system (IMS) can be used to provide
information about the operation and production of the facility. This can be a
separate system, or an integral part of the control system or SCADA system.
Figure 35. Information management system topology
For oil and gas, IMS functionality includes:
• Oil & gas production reporting
• Safety management
• Maintenance
• Operator support
• Overall systems integrated and external
• Historical data, including post failure "flight recorder" data
Some of the applications provided by an IMS system may be:
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• Drilling data acquisition and drilling data logging
• Electronic shift logbook
• Operator procedures
• Chemical injection
• Chemical consumption
• Laboratory analysis registration
• Alarm and incidents overview
• Alarm Statistics
• Valve leakage test
• Transmitter surveillance
• Run time monitoring
• Block log
• Production plan
• SIL statistics report
• Subsea valve signatures
• Production overview and prognosis
• Valve verification
• ESD/PSD verification, including shutdown analysis
• Data export
• Data browser tool
• Historical data and current trend
• Well test
• Daily production report with metering data
• Volumes in storage cells and consolidation of produced stored and
dispatched volumes.
• Environmental reports
• Polynomial allocation (oil/gas/water) based on well test results
8.2.5 Training simulators
Training simulators are used to
provide operator training in a
realistic plant training
environment. They use the
actual control and safety
applications of the plant,
running on operator stations.
Plant models simulate the
feedback from the plant in real
time, or in fast or slow motion.
Training simulator applications
include functions for backup and
reload, including recreation of historical information and snapshots. Offsite
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training facilities are often connected (read only) to the live plant to provide
information from the real operating situation.
8.3 Power generation, distribution and drives
Power can be provided from mains power,
local gas turbines or diesel generator sets.
Large facilities have high power demands,
from 30 MW up to several hundred MW.
There is a tendency to generate electric
power centrally and use electric drives for
large equipment rather than multiple gas
turbines, as this decreases maintenance
and increases uptime.
The power generation system on a large
facility is usually several gas turbines
driving electric generators, 20-40 MW
each. Exhaust heat is often needed in the
main process.
Figure 36. Electrical single line diagram
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Voltage levels for high, medium and low voltage distribution boards are 13-
130 kV, 2-8 kV and 300-600 V respectively. Power is generated and
exchanged with mains or other facilities on the HV distribution board. Relays
are used for protection functions.
HV is transformed to MV switchboards, to which large consumers are
connected. LV switchboards feed a mix of normal consumers, motor control
centers (MCC) and variable speed drives for motors up to a few hundred KW
(not necessarily separately, as shown in the figure below).
A separate emergency power switchboard provides power for critical
equipment. It can be powered from a local emergency generator if main
power is lost. Computer systems are fed from an uninterruptible power
system (UPS) with batteries, connected to the main or emergency
switchboard.
A power management system is used for control of electrical switchgear and
equipment. Its function is to optimize electricity generation and usage and to
prevent major disturbances and plant outages (blackouts). The power
management system includes HV, MV and LV low voltage switchgear plus
MCCs and emergency generator sets. Functions include prioritization of
loads, emergency load shedding (closing down of nonessential equipment)
and prestart of generator sets (e.g., when additional power to start a big
crude pump is required).
Large rotating equipment
and generators are driven by
gas turbines or large drives.
Gas turbines for oil and gas
production are generally
modified aviation turbines in
the 10-25 MW range. These
require quite extensive
maintenance and have a
relatively low overall
efficiency (20-27%,
depending on application).
Also, while a turbine is
relatively small and light, it
will usually require large and heavy support equipment such as large gears,
air coolers/filters, exhaust units, and sound damping and lubrication units.
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Therefore use of large variable speed drives is becoming more common. For
pumps on subsea facilities, this is the only option. For use on remote
facilities, High voltage DC transmission and HV motors can be used, from a
main facility or power from shore. This avoids local power generation at each
facility and contributes to low manning or remote operation.
8.4 Flare and atmospheric ventilation
Flare subsystems include flare, atmospheric ventilation and blowdown. The
purpose of the flare and vent systems is to provide safe discharge and
disposal of gases and liquids resulting from:
• Spill-off flaring from the product stabilization system. (oil,
condensate, etc.)
• Production testing
• Relief of excess pressure caused by process upset conditions and
thermal expansion
• Depressurization, either in response to an emergency situation or as
part of a normal procedure
• Planned depressurization of subsea production flowlines and export
pipelines
• Venting from equipment operating close to atmospheric pressure
(e.g., tanks)
The systems are typically divided into a
high pressure (HP) flare and a low pressure
(LP) flare system. The LP system is
operated slightly above atmospheric
pressure to prevent atmospheric gases
such as oxygen flowing back into the vent
and flare system and generating a
combustible mixture. With low gas flow,
inert gas is injected at the flare nozzle to
prevent air ingress.
Traditionally, considerable amounts of
hydrocarbons have been more or less
continuously flared. In these cases, a
continuously burning pilot is used to ensure
ignition of hydrocarbons in the flare.
Stronger environmental focus has eliminated continuous flaring and the pilot
in many areas. Vapors and flare gas are normally recovered, and only in
exceptional situations does flaring occur. To avoid the pilot flame, an ignition
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system is used to ensure safe ignition, even when large volumes are
discharged. One patented solution is a "ballistic ignition" system which fires
burning pellets into the flare gas flow.
8.5 Instrument air
A large volume of compressed air is required for control of pneumatic valves
and actuators, tools and purging of cabinets. It is produced by electrically
driven screw compressors and further treated to be free of particles, oil and
water.
8.6 HVAC
The heat, ventilation and air conditioning system (HVAC) feeds conditioned
air to the equipment and accommodation rooms, etc. Cooling and heating is
achieved by water-cooled or water/steam-heated heat exchangers. Heat
may also be taken from gas turbine exhaust. In tropical and sub-tropical
areas, cooling is achieved by compressor refrigeration units. In tropical
areas, gas turbine inlet air must be cooled to achieve sufficient efficiency and
performance. The HVAC system is usually delivered as one package, and
may also include air emissions cleaning. Some HVAC subsystems include:
• Cool: cooling medium, refrigeration system, freezing system
• Heat: heat medium system, hot oil system
One function is to provide air to equipment rooms that are secured by
positive pressure. This prevents potential influx of explosive gases in case of
a leak.
8.7 Water systems
8.7.1 Potable water
For smaller installations,
potable water can be
brought in by supply
vessels or tank trucks.
Photo: Lenntech Water
treatment and air purification
Holding B.V.
For larger facilities, it is
provided on site by
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desalination of seawater though distillation or reverse filtering. Onshore
potable water is provided by purification of water from above or below
ground reservoirs.
Reverse filtering or osmosis requires a membrane driving pressure of about
7000 kPa/1 PSI of pressure per 100 ppm of solids dissolved in the water. For
seawater with 3.5% salt, 2.5 MPa, 350 PSI is required.
8.7.2 Seawater
Seawater is used extensively for cooling purposes. Cold water is provided to
air compressor coolers, gas coolers, main generators and HVAC. In addition,
seawater is used for the production of hypochlorite (see chemicals) and for
fire water. Seawater is treated with hypochlorite to prevent microbiological
growth in process equipment and piping.
Seawater is sometimes used for reservoir water injection. In this case, a
deaerator is used to reduce oxygen in the water before injection. Oxygen
can cause microbiological growth in the reservoir. The deaerator is designed
to use strip gas and vacuum.
8.7.3 Ballast water
Ballast systems are found on drilling rigs, floating production ships, rigs and
tension leg platforms (TLP). The object is to keep the platform level at a
certain depth under varying conditions, such as mode of operation
(stationary drilling, movement), climatic conditions (elevation of rig during
storms), amount of product in storage tanks, and to adjust loading on TLP
tension members.
Ballasting is accomplished by means of ballast tanks, pumps and valves,
which are used in combination with position measuring instruments and
tension force meters (TLP) to achieve the desired ballasting.
If fresh water is produced, it can be used as ballast to avoid salt water.
Additionally, if ballast water has become contaminated from oil tanks, it must
be cleaned before discharge at sea.
8.8 Chemicals and additives
A wide range of chemical additives are used in the main process. Some of
these are marked in the process diagram. The cost of process chemical
additives is considerable. A typical example is antifoam, where a
concentration of about 150 ppm is used. With a production of 40,000 bpd,
about 2,000 liters (500 gallons) of antifoam can be used. At a cost of 2 € per
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liter, ($10 per gallon) in bulk, antifoam alone will cost some 4,000 € or
$5,000 per day.
The most common chemicals and
their uses are:
Scale inhibitor
Emulsion breaker
Antifoam
The well flow
contains
several
different
contaminants,
such as salts,
chalk and
traces of
radioactive
materials. As pressure and temperature change, these
may precipitate and deposit in pipes, heat
exchangers, valves and tanks. As a result, they may
clog up or become stuck. The scale inhibitor prevents
the contaminants from separating out. Scale or
sediment inhibitor is applied to wellheads and
production equipment.
Water and oil cannot mix to form a true solution.
However, small drops of oil can disperse in water and
small water drops can disperse in oil. Such systems
are called emulsions; oil-in-water (o/w) and water-inoil
(w/o), respectively. The drops are held suspended
by electrostatic repulsion, and will form a distinct layer
between the oil and water. Sand and particles are
normally carried out by the water extracted in water
treatment. However, the emulsion can trap these
particles and sink to the bottom as a sticky sludge that
is difficult to remove during operation. Although the
emulsion layer will eventually break down naturally, it
takes time, too much time. An emulsion breaker is
added to prevent formation and promote breakdown of
the emulsion layer by causing the droplets to merge
and grow.
The sloshing motion inside a separator causes
foaming. This foam covers the fluid surface and
prevents gas from escaping. Foam also reduces the
gas space inside the separator, and can pass the
demister and escape to the gas outlet in the form of
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Polyelectrolyte
Methanol (MEG)
TEG
Hypochlorite
Biocides
mist and liquid drops. An antifoam agent is introduced
upstream of the separator to prevent or break down
foam formation by reducing liquid surface tension.
Polyelectrolyte is added before the hydrocyclones and
causes oil droplets to merge. This works by reducing
surface tension and water polarity. This is also called
flocculation, and polyelectrolyte flocculants allow
emissions to reach 40 ppm or less.
Methanol or monoethylene glycol (MEG) is injected in
flowlines to prevent hydrate formation and prevent
corrosion. Hydrates are crystalline compounds that
form in water crystalline structures as a function of
composition, temperature and pressure. Hydrates
appear and freeze to hydrate ice that may damage
equipment and pipelines.
For normal risers, hydrates form only when production
stops and the temperature starts to drop. Hydrate
formation can be prevented by depressurization which
adds to startup time, or by methanol injection.
On longer flowlines in cold seawater or Arctic
climates, hydrates may form under normal operating
conditions and require continuous methanol injection.
In this case, the methanol can be separated and
recycled.
Hydrate prediction model software can be used to
determine when there is a risk of hydrate formation
and to reduce methanol injection or delay
depressurization.
Triethyleneglycol (TEG) is used to dry gas (see the
chapter on scrubbers and reboilers).
Hypochlorite is added to seawater to prevent growth
of algae and bacteria, e.g., in seawater heat
exchangers. Hypochlorite is produced by electrolysis
of seawater to chlorine. In one variant, copper
electrodes are used, which adds copper salts to the
solution that improves effectiveness.
Biocides are also preventive chemicals that are added
to prevent microbiological activity in oil production
systems, such as bacteria, fungus or algae growth.
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Particular problems arise from the growth of sulfate
reducing bacteria that produces hydrogen sulfide and
clogs filters. Typical uses include diesel tanks,
produced water (after hydrocyclones), and slop and
ballast tanks.
Corrosion inhibitor Corrosion inhibitor is injected in export pipelines and
storage tanks. Exported oil can be highly corrosive,
leading to corrosion of the inside of the pipeline or
tank. The corrosion inhibitor protects by forming a thin
film on metal surfaces.
Drag reducers
Drag reducers improve the flow in pipelines. Fluid
near the pipe tries to stay stationary while fluid in the
center region of the pipe is moving quickly. This large
difference in fluid causes turbulent bursts to occur in
the buffer region. Turbulent bursts propagate and form
turbulent eddies, which cause drag.
Drag-reducing polymers are long-chain, ultra-high
molecular weight polymers from 1 to 10 million u), with
higher molecular weight polymers giving better drag
reduction performance. With only parts-per-million
levels in the pipeline fluid, drag-reducing polymers
suppress the formation of turbulent bursts in the buffer
region. The net result of using a drag-reducing
polymer in turbulent flow is a decrease in the frictional
pressure drop in the pipeline by as much as 70%. This
can be used to lower pressure or improve throughput.
8.9 Telecom
Traditionally, all electronic systems that do not fall naturally under the
electrical or automation bracket are grouped as telecommunication systems.
As such, the telecom system consists of a variety of subsystems for human
and computer wired and wireless communications, monitoring, observation,
messaging and entertainment.
Some of the main systems are:
· Public address and alarm system/F&G integration
· Access control
· Drillers talk-back system
· UHF radio network system
· Closed circuit TV system
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· Mandatory radio system
· Security access control
· Meteorological system/sea wave radar
· Telecom antenna tower and antennas
· PABX telephone system
· Entertainment system
· Marine radar and vessel movement system
· Office data network and computer system
· Personnel paging system
· Platform personnel registration and tracking system
· Telecom management and monitoring system
· Ship communication system/PABX extension
· Radio link system
· Mux and fiber optical terminal equipment
· Intrusion detection
· Satellite systems
The systems are often grouped in four main areas:
1. External communication
External communication
systems
interconnect
installations and link them to the
surrounding world – carrying
voice, video, process control
and safety system traffic
necessary to allow uninterrupted
safe facility operations. With
today's solutions and
technologies, distance is no
longer an issue and bandwidth
is available as needed, either on demand or fixed. This opens up new ideas
and opportunities to reduce operational costs in the industry.
2. Internal communication
Internal telecommunication systems play a
major role in supporting day-to-day operations
and improving the working environment. They
allow any type of system or operator to
communicate within the facility, enabling
reliable and efficient operations.
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3. Safety and Security Systems
Safety and Security Systems are used for
safeguarding personnel and equipment in, on
and around an installation according to
international rules and standards. These
systems are often adapted to meet
local/company safety requirements. For best
possible performance and flexibility, safety
systems are closely integrated with each other,
as well as to other internal and external systems.
4. Management and utility systems
System and personnel well-being are supported by a number of
management and utility systems that are intended to ease and simplify
telecom maintenance and operations.
In today's O&G world, all of these systems play an important role in laying
the foundations for remote operation, diagnostics and maintenance of
integrated operations.
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9 Unconventional and conventional
resources and environmental effects
About 81.1% of the world’s primary energy consumption in 2012 was fossil
fuels; 27.3% was coal, oil production was 32.4% or about 4.01 billion tons,
and 21.4% was gas, with 3,39 trillion scm or 3.01 billion tons oil equivalent
(TOE). Thus, total oil and gas production was 6.4 billion TOE, which is about
128.5 million barrels of oil equivalent per day (IEA 2012).
Proven reserves are estimated at 201 billion TOE of oil and 6707 tcf of gas
(180 trillion scm, 160 billion TOE) for a total of 361 billion TOE (converted
from estimates by US Department of Energy, 2012), indicating that proven
reserves will last for about 56 years.
9.1 Unconventional sources of oil and gas
The reservoirs described earlier are called conventional sources of oil and
gas. As demand increases, prices soar and new conventional resources
become economically viable. At the same time, production of oil and gas
from unconventional sources becomes more attractive. These
unconventional sources include very heavy crudes, oil sands, oil shale, gas
and synthetic crude from coal, coal bed methane, methane hydrates and
biofuels. At the same time, improved oil recovery (IOR) can improve the
percentage of the existing reservoirs that can be economically extracted.
These effects are illustrated in principle in the following figure.
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Estimates of undiscovered conventional and unconventional sources vary as
widely as the oil price among different sources. The figure illustrates that if
one assumes that if an oil price of $100 per barrel prevails, the estimated
economically recoverable reserves with current technology will be about 800
billion tons of oil equivalent, of which 45% is proven. This is about 125 years
of consumption at current rates, and is expected that up to a third of oil fuel
production may come from unconventional sources within the next decade.
9.1.1 Extra heavy crude
Very heavy crude are hydrocarbons with an API grade of about 15 or below.
The most extreme heavy crude currently extracted is Venezuelan 8 API
crude, e.g., in eastern Venezuela (Orinoco basin). If the reservoir
temperature is high enough, the crude will flow from the reservoir. In other
areas, such as Canada, the reservoir temperature is lower and steam
injection must be used to stimulate flow from the formation.
When reaching the surface, the crude must be mixed with diluents (often
LPGs) to allow it to flow in pipelines. The crude must be upgraded in a
processing plant to make lighter SynCrude with a higher yield of high value
fuels. Typical SynCrude has an API of 26-30. The diluents are recycled by
separating them out and piping them back to the wellhead site. The crude
undergoes several stages of hydrocracking and coking to form lighter
hydrocarbons and remove coke. It is often rich in sulfur (sour crude), which
must be removed.
9.1.2 Tar sands
Tar sands can often be strip-mined. Typically, two tons of tar sand will yield
one barrel of oil. Typical tar sand contains sand grains with a water
envelope, covered by a bitumen film that may contain 70% oil. Various fine
particles can be suspended in the water
and bitumen.
This type of tar sand can be processed
with water extraction. Hot water is added
to the sand, and the resulting slurry is
piped to the extraction plant where it is
agitated and the oil skimmed from the
top. Provided that the water chemistry is
appropriate (the water is adjusted with
chemical additives), it allows bitumen to
separate from sand and clay. The
combination of hot water and agitation
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eleases bitumen from the oil sand, and allows small air bubbles to attach to
the bitumen droplets. The bitumen froth floats to the top of separation
vessels, and is further treated to remove residual water and fine solids. It can
then be transported and processed the same way as extra heavy crude.
It is estimated that around 80% of tar sands are too far below the surface for
current open-cast mining techniques. Techniques are being developed to
extract the oil below the surface. This requires a massive injection of steam
into a deposit, thus liberating the bitumen underground, and channeling it to
extraction points where it can be liquefied before reaching the surface. The
tar sands of Canada (Alberta) and Venezuela are estimated at 250 billion
barrels, equivalent to the total reserves of Saudi Arabia.
9.1.3 Oil shale
Most oil shales are fine-grained sedimentary rocks containing relatively large
amounts of organic matter, from which significant amounts of shale oil and
combustible gas can be extracted by destructive distillation. Significant shale
“plays” have been discovered in the last decade, such as the Marcellus in
the northern US and Canada, Eagle Ford on the US east coast and Bakken
in south Texas.
Oil shale differs from coal in that organic matter in shales has a higher
atomic hydrogen to carbon ratio. Coal also has an organic to inorganic
matter ratio of more than 4, i.e., 75 to 5, while oil shales have a higher
content of sedimentary rock. Sources estimate the world reserves of oil
shales at more than 2.5 trillion barrels.
Oil shales are thought to form when algae and sediment deposit in lakes,
lagoons and swamps where an anaerobic (oxygen-free) environment
prevents the breakdown of organic matter, thus allowing it to accumulate in
thick layers. These layers were later covered with overlying rock, to be
baked under high temperature and pressure. However, the heat and
pressure were lower than in oil and gas reservoirs.
Shale can be strip-mined and processed with distillation. Extraction with
fracturing and heating is still relatively unproven. Companies are
experimenting with direct electrical heating rather than steam injection.
Extraction cost is currently around $25-30 per barrel.
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9.1.4 Shale gas and coal bed methane
Oil shales are also becoming an important source of shale gas, and some
analysts expect that this source of natural gas can supply half of the gas
consumption in the US and Canada by 2020. Shales normally do not have
the required matrix permeability for the gas to be produced, and in the past,
gas could be produced only from source rock with significant natural
fracturing. The natural gas comes from decomposition of shale oil and is
held in natural fractures, some in pore spaces, and some adsorbed onto
organic material. Recently, there have been strong advances in extraction
technology, which uses a combination of horizontal wells and hydraulic
fracturing in a way that maintains fracturing (see chapter 3.7) and flow of gas
much better than before. Even so, production typically requires a high
number of wells with limited lifetimes, so continuous drilling of new wells is
required to maintain output. Methane is a potent greenhouse gas, and
emissions from leaking capped wells and fractures is a potential problem
due to the large number of wells.
Figure 37. Schematic geology of natural gas resources
This form of production is different from oil shale gas, which is produced by
pyrolysis (heating and hydrocarbon decomposition) of mined oil shale.
Coal deposits also contain large amounts of methane, referred to as coal
bed methane. The methane is absorbed in the coal matrix and requires
extraction techniques similar to shale gas. Often the coal bed is flooded, so
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after well completion and fracturing, the coal seam (layer of coal) must be
dewatered. A common solution is to extract water through the well tubing.
Generally, the water needs to be pumped out and therefore control is
needed to prevent the gas from entering the water in the tubing (the well
becomes gassy). This reduces the pressure and allows methane to desorb
from the matrix and be produced through the casing.
9.1.5 Coal, gas to liquids and synthetic fuel
Coal is similar in origin to oil shales, but typically formed from the anaerobic
decay of peat swamps and relatively free from non-organic sediment
deposits, reformed by heat and pressure. To form a 1-meter thick coal layer,
as much as 30 meters of peat was originally required. Coal can vary from
relatively pure carbon to carbon soaked with hydrocarbons, sulfur, etc.
(For synthesis gas, see also chapter 7.3.)
It has been known for decades that synthetic diesel could be created from
coal. This is done, first by creating water gas as synthesis gas by passing
steam over red-hot coke. The reaction is endothermic and requires heating:
C + H 2 O → H 2 + CO
More hydrogen is produced in the water gas shift reaction:
CO + H 2 O → H 2 + CO 2
Often two stages are used: a high temperature shift (HTS) at 350 °C with
catalyst iron oxide promoted with chromium oxide, and a low temperature
shift (LTS) at 190–210 °C with catalyst copper on a mixed support composed
of zinc oxide and aluminum oxide.
These synthesis gases are then used in the Fischer–Tropsch process:
(2n+1)H 2 + nCO → C n H (2n+2) + nH 2 O
This process runs at a pressure of 2-4 MPa. With iron catalyst a high
temperature process at 350 °C will yield a diesel fuel quite similar to normal
diesel with an average carbon number of 12, and a certain content of
unwanted aromatics. The low temperature process uses a cobalt catalyst
and a temperature of 200 °C and yields a pure synthetic diesel composed of
alkanes with a carbon number of 10-15 and an average carbon number of
12.
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Synthesis gas can also be created from natural gas by lean combustion or
steam reforming:
CH 4 + 1/2O 2 → CO + 2H 2
CH 4 + H 2 O → CO + 3H 2
Lean combustion
Steam reforming
This can be fed to the water shift reaction and to the F-T process. This
process, together with the following application, are often called gas to
liquids (GTL) processes.
An alternative use of the synthesis gases (CO and H 2 ) is production of
methanol and synthetic gasoline:
2 H 2 + CO → CH 3 OH Methanol synthesis
Then, the methanol is converted to synthetic gasoline in the Mobil process.
2 CH 3 OH → CH 3 OCH 3 + H 2 O Dehydration to dimethyl ether
The second stage further dehydrates the ether with ceolite catalyst to yield a
synthetic gasoline with 80% carbon number 5 and above.
9.1.6 Methane hydrates
Methane hydrates are the most recent form of
unconventional natural gas to be discovered
and researched. These formations are made
up of a lattice of frozen water, which forms a
sort of cage around molecules of methane.
Hydrates were first discovered in permafrost
regions of the Arctic and have been found in
most of the deepwater continental shelves
tested. The methane originates from organic
decay.
At the sea bottom, under high pressure and low temperatures, the hydrate is
heavier than water and cannot escape. Research has revealed that this form
of methane may be much more plentiful than first expected. Estimates range
anywhere from 180 to over 5800 trillion scm.
The US Geological Survey estimates that methane hydrates may contain
more organic carbon than all the world's coal, oil, and conventional natural
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gas – combined. However, research into methane hydrates is still in its
infancy.
9.1.7 Biofuels
Biofuels are produced from specially-grown products such as oilseeds or
sugars, and organic waste, e.g., from the forest industry. These fuels are
called carbon neutral, because the carbon dioxide (CO 2 ) released during
burning is offset by the CO 2 used by the plant when growing.
Ethanol alcohol (C 2 H 5 OH) is distilled from fermented sugars and/or starch
(e.g., wood, sugar cane or beets, corn (maize) or grain) to produce ethanol
that can be burned alone with retuning of the engine, or mixed with ordinary
gasoline.
Biodiesel is made from oils from crops such as rapeseed, soy, sesame, palm
or sunflower. The vegetable oil (lipid) is significantly different from mineral
(crude) oil, and is composed of triglycerides. In these molecules, three fatty
acids are bound to a glycerol molecule shown in the following picture (The
wiggly line represents the carbon chain with a carbon atom at each knee
with single or double bonds and two or one hydrogen atoms respectively):
Figure 38, Vegetable Oil structure
The glycerol backbone on the left is bound (ester OH binding) to three fatty
acids, shown here with palmitic acid, oleic acid and alpha-linolenic acid and
a total carbon number of 55.
This molecule is broken down to individual alkyl esters through a chemical
process called transesterification, whereby the glycerin is separated from the
fatty acids. Methanol (CH 3 OH) is added to the lipids and heated. Any strong
base capable of deprotonating the alcohol, such as NaOH or KOH is used as
catalyst.
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The process leaves behind methyl esters (with a CH 3 group on the ester
binding) and glycerin (a valuable byproduct used in soaps, explosives and
other products).
Figure 39. Transesterification
Biodiesel contains no petroleum, but it can be blended at any level with
petroleum diesel to create a biodiesel blend. It can be used in compressionignition
(diesel) engines with little or no modification. Biodiesel is simple to
use, biodegradable, non-toxic, and essentially free of sulfur and aromatics.
Although biofuel is carbon-neutral, concern has been raised about diverting
agricultural areas away from food production. Recently, research has shown
potential for growing certain strains in arid regions that could not otherwise
be used for producing human food.
An alternative to the above process that is still at the research stage is
genetically modified E. coli bacteria. E. coli can produce enzymes to break
down cellulose to sugar, which can then be used to produce biodiesel. This
method allows use of general biological waste and limit competition with
human food resources.
134

9.1.8 Hydrogen
Although not a hydrocarbon resource, hydrogen can be used in place of or
as a complement to traditional hydrocarbon-based fuels. As an "energy
carrier,” hydrogen is clean burning, which means that when hydrogen reacts
with oxygen, either in a conventional engine or a fuel cell, water vapor is the
only emission. (Combustion with air at high temperatures will also form
nitrous oxides).
Hydrogen can be produced either from hydrocarbons (natural gas, ethanol,
etc.) or by electrolysis. Production from natural gas is often done via syngas
(see chapter 9.1.5) with up to 75-80% efficiency. Its advantage over
methane gas is that carbon dioxide can be removed and handled at a central
location rather than by each consumer, providing a cleaner energy carrier.
Hydrogen is also produced from water by electrolysis with an efficiency of
about 25% at normal conditions, to about 50% in high temperature, high
pressure processes, or in various recycling processes in the chemical
industry. (e.g., hydrochloric acid recycled in the polyurethane process). The
energy supply can then come from a renewable source such as
hydroelectric, solar, wind, wave, or tidal, where hydrogen acts as an energy
carrier replacing batteries, to form a fully clean, renewable energy source
supply chain.
In both cases, the main problem is overall economy, distribution and storage.
Hydrogen cannot easily be compressed to small volumes, and requires quite
bulky gas tanks for storage. Also, hydrogen produced from electricity
currently has an end-to-end efficiency that does not compare well with
gasoline or electrical battery vehicles.
9.2 Emissions and environmental effects
The production, distribution and consumption of hydrocarbons as fuel or
feedstock are globally the largest source of emissions into the environment.
The total annual world energy supply of 11,000 million TOE is based 81% on
fossil fuels, and releases some 26,000 million tons of carbon dioxide plus
other gases, e.g., methane into the atmosphere.
The most serious effect of these emissions is global climate change. The
Intergovernmental Panel on Climate Change (often called the UN Climate
Panel) predicts that these emissions will cause the global temperature to rise
from between 1.4 to 6.4 ºC by the end of the 21 st century, depending on
models and global scenarios.
135

9.2.1 Indigenous emissions
Emissions from the industry can be divided into several types.
Discharge:
Accidental spills:
Emissions:
Mud, shale, silt, produced water with traces of
hydrocarbons. Ballast water, polluted wastewater with
detergent, sewage, etc.
Blowout, shipwreck cargo and bunker oil, pipeline
leakage, other chemicals, traces of low level
radioactive isotopes.
CO 2 , methane, nitrous oxides (NO x ) and sulfur from
power plants and flaring
Exposure:
Toxic and/or carcinogenic chemicals
Locally, these emissions are tightly controlled in most countries by national
and international regulations, and during normal operations, emission targets
can be reached with the systems and equipment described earlier in this
document. However, there is continuing concern and research into the
environmental impact of trace levels of hydrocarbons and other chemicals on
the reproductive cycle and health of wildlife in the vicinity of oil and gas
installations.
The major short-term environmental impact is from spills associated with
accidents. These spills can have dramatic short-term effects on the local
environment, with damage to marine and wildlife. However, the effects
seldom last for more than a few years outside Arctic regions.
9.2.2 Greenhouse emissions
The most effective greenhouse gas is water vapor. Water naturally
evaporates from the sea and spreads out, and can amplify or suppress the
other effects because of its reflective and absorbing capability.
The two most potent emitted greenhouse gases emitted are CO 2 and
methane. Because of its heat-trapping properties and lifespan in the
atmosphere, methane's effect on global warming is 22-25 times higher than
CO 2 per kilo released to atmosphere. By order of importance to greenhouse
effects, CO 2 emissions contribute 72-77%, methane 14-18%, nitrous oxides
8-9% and other gases less than 1%. (sources: Wikipedia, UNEP)
The main source of carbon dioxide emissions is burning of hydrocarbons.
Out of 29 billion tons (many publications use teragram (Tg) = million tons) of
CO 2 emitted in 2008, 18 billion tons or about 60% of the total comes from oil
136

and gas, the remainder is coal, peat and renewable bioenergy, such as
firewood. 11% or 3.2 billion tons comes from the oil and gas industry itself in
the form of losses, local heating, power generation, etc.
The annual emissions are about 1% of total atmospheric CO 2 , which is in
balance with about 50 times more carbon dioxide dissolved in seawater. This
balance is dependent on sea temperature: Ocean CO 2 storage is reduced as
temperature increases, but increases with the partial pressure of CO 2 in the
atmosphere. Short term, the net effect is that about half the CO 2 emitted to
air contributes to an increase of atmospheric CO 2 by about 1.5 ppm annually.
For methane, the largest source of human activity-related methane
emissions to atmosphere is from rice paddies and enteric fermentation in
ruminant animals (dung and compost) from 1.4 billion cows and buffalos.
These emissions are estimated at 78.5 Tg/year (source: FAO) out of a total
of 200 Tg, which is equivalent to about 5,000 Tg of CO 2 . Methane from the
oil and gas industry accounts for around 30% of emissions, mainly from
losses in transmission and distribution pipelines and systems for natural gas.
Figure 40. Greenhouse emissions Source: Wikipedia Commons
137

There are many mechanisms affecting the overall balance of greenhouse
gases in the atmosphere. CO 2 has been measured both directly and in ice
cores, and has increased from a pre-industrial value of around 250 ppm to
385 ppm today. Methane has increased from 1732 to 1774 ppb (parts per
billion).
There is no full model that describes the net effect of these changes. It is
well accepted that without CO2, methane and water vapor, the global
average temperature would be about 30 ºC colder. The current data
correlates well with a current global average temperature increase from a
pre-industrial global average of 13.7 ºC to 14.4 ºC today. The atmosphere
and seas have large heat trapping capacity, which makes their temperatures
rise. These temperature rises lag behind greenhouse gas temperature
increases. It is therefore predicted that the temperature will continue to rise
by about 1ºC even if there were no further increase in levels of CO 2 and
methane.
The heat capacity of the atmosphere and seas also means that when the
temperature increases, there will be more energy stored in the atmosphere,
which is expected to drive more violent weather systems.
Organic Sediments
Oil, Gas Coal -------------------------
Carbonates
Absorbtion
Erosion & Sediments
Volcanoes release
Figure 41. Carbon cycle
138

The main contribution to sea level change in the short-to-medium term is
thermal expansion of the oceans, currently predicted to have reached about
0.15 m over pre-industrial standards, and currently rising some 3 mm/year.
Although the melting of inland ice in Greenland and Antarctica is reported,
this will mainly have local effects, as this ice will possibly take 15-20,000
years to have any significant contribution to sea levels. However, polar
glaciation and sea ice is an important indicator of global warming, and in
particular, Arctic summer temperatures have risen and sea ice has been
significantly reduced in area and thickness.
9.2.3 Carbon capture and sequestration
Due to these effects and the long-term concerns, it will be a high priority to
reduce the amount of carbon dioxide and methane released into the
atmosphere, and to develop more sustainable energy sources. The main
problem is that as much as one third of all emissions come from planes, cars
and ships, which account for about 45% of emissions from hydrocarbon fuels
that are not replaceable by other known energy sources at this time.
There are three main problem areas:
• There are losses in production: Only about 70% of hydrocarbons
extracted from the ground reach the private or industrial consumer.
The rest is lost from production systems, transportation and through
the refining and distribution of oil and gas.
• There are losses in consumption: Much of the oil and gas is
converted to work with an efficiency of 30% in cars, for example, to
60% in the best power plants.
• Better methods for capturing and storing emissions must also be
found.
Efficiency will be improved by maintaining and operating facilities to reduce
losses, and by converting to more efficient systems. For example, it can be
argued that conversion to electrically-driven equipment in place of gas
turbine-driven equipment could reduce CO 2 emissions by more than 50%,
even if power is generated by a gas turbine and steam combined cycle unit.
This also moves the emissions to a centralized unit rather than distributing to
a larger number of smaller gas turbines.
To reduce overall emissions, carbon will have to be separated from other
emitted gases (such as water vapor) and stored. Current plans call for reinjection
into empty reservoirs, or reservoirs that need pressure assistance
for oil extraction.
139

Capturing CO2 can be done at large point sites, such as large fossil fuel or
biomass energy facilities, industries with major CO 2 emissions, natural gas
processing, synthetic fuel plants and fossil fuel-based hydrogen production
plants:
Overall there are three types of processes:
• Pre-combustion systems, where the fuel is gasified and processed
before combustion, and carbon dioxide can be removed from a
relatively pure exhaust stream.
• Post-combustion systems, where carbon dioxide is extracted from
the flue gas, e.g., using an amine process.
• Oxyfuel consumption, where fuel is burned as relatively pure
oxygen, so the hydrocarbon is burned in oxygen instead of air. This
produces a flue gas consisting of only carbon dioxide and water
vapor, which is cooled and condensed.
For storage:
• A system to store, transport and inject gas into existing reservoirs.
This is done by a pipeline, which is generally the cheapest form of
transport, or by ship if pipelines are not available.
• Alternatives to storage include carbonatization, deep sea deposit,
and planting of photosynthetic plants in otherwise infertile areas.
Currently these processes could remove around 90% of CO 2 at a cost of
$35-90 per ton, including injection and storage in a reservoir. This is about 2-
3 times the long-term expected emission quota costs.
140

10 Units
Some common units used in the oil and gas industry are listed here as a
representative selection of US and metric units, since both are used in
different parts of the oil industry. The non-standard factors differ slightly
between different sources.
API American Petroleum
Institute crude grade
API = (141.5 / Specific gravity ) – 131.5
Spec gravity = 141.5/(API + 131.5) kg/l
Bl Barrel (of oil) 1 Bl = 42 Gallons
1 Bl = 159 liters
1 Bl equiv. to 5487 scf = 147 scm gas
Bpd Barrel per day 1 Bpd ≈ 50 tons/tons per year
BTU British thermal unit 1 BTU = 0.293 Wh = 1,055 kJ
Cal Calorie 1 Cal = 4,187 J (Joules)
MMscf Million standard cubic 1 MMscf = 23.8 TOE ≈ 174 barrels
feet
psi Pounds per square 1 psi = 6.9 kPa = 0.069 atm
Scf
Scm
TOE
kWh
inch
Standard cubic feet
(of gas) defined by
energy, not a normalized
volume
Standard cubic meter
(of gas, also Ncm)
Defined by energy
content
Tons oil equivalent
Range 6.6 - 8 barrels at
API range 8 - 52
Kilowatt hour
= 1000 joules * 3600 S
1 scf = 1000 BTU = 252 kcal
= 293 Wh = 1,055 MJ
≈ 0.0268 scm
1 Scm = 39 MJ = 10.8 kWh
1 Scm ≈ 37.33 Scf (not a volume conv.)
1 Scm ≈ 1.122 kg
1 TOE = 1000 kg = 1 Ton (metric) oil
1 TOE = 1 Tone oil (US)
1 TOE ≈ 7.33 Barrels (at 33 API)
1 TOE ≈ 42.9 GJ =11,9 MWh
1 TOE ≈ 40.6 MMBTU
1 TOE ≈ 1.51 ton of coal
1 TOE ≈ 0.79 ton LNG
1 TOE ≈ 1,125 Scm = 42,000 Scf
1 kWh = 3.6 MJ = 860 kcal = 3,413 BTU
141

Product specific gravity, API grades
Product
Liters Per Ton API Specific Barrels per
(metric) Grade Gravity
(kg/m3)
Ton
At 60°F
LPG 1835 10 1000 6.29
Jet A-1 1254 18 934 6.73
Gasoline
1353 25 904 6.98
premium/super
Gasoline regular 1418 30 876 7.19
Kerosene 1273 33 860 7.33
Gas oil 1177 36 845 7.46
Diesel fuel 1159 39 830 7.60
Fuel oil 80 CST 1065 42 816 7.73
Fuel oil 180 CST 1050 50 780 8.06
Fuel oil 230 CST 1047
Fuel oil 280 CST 1044
Bitumen 979
CO2 Emissions from burning of coal and hydrocarbons
Product Average CO 2 kg CO 2 kg Other unit
Carbon No per kg Per kWh
Methane 1 2,75 0,178 1,92 kg CO 2 / scm
Gasoline 8 3,09 0,241 2,28 kg CO 2 / liter
Diesel 12 3,11 0,249 2,68 kg CO 2 / liter
Fuel oil 25 3,12 0,268 3,97 kg CO 2 / liter
Coal 1 3,67 0,325
142

11 Glossary of terms and acronyms
ABS
AC
AGA
AO
API
BPA
BTX
CAPEX
CCR
CDU
CMMS
CMS
CNG
CPF
CSP
DC
DEA
DEGBE
DEGBEA
DETA
DPGEE
DPGME
DYNPOS
E&P
EDTA
EG
EGBE
EGBEA
EO
EOR
EPA
EPS
ESD
ESP
ETBE
Acrylonitrile-butadiene-styrene
Alternating current
American Gas Association
Asset optimization
American Petroleum Institute
Bisphenol A
Benzene, toluene and xylenes
Capital Expenses (Invested capital)
Central control room
Crude Oil Distillation Unit
Computerized maintenance management
system
Condition monitoring systems
Compressed natural gas
Central processing facility
Collector and separation platform
Direct current
Diethanolamine
Diethylene glycol butyl ether
Diethylene glycol butyl ether acetate
Diethylenetriamine
Dipropylene glycol ethyl ether.
Dipropylene glycol methyl ether.
Dynamic positioning (of rigs and ships)
Exploration and production
Ethylenediamine tetraacetic acid
Ethylene glycol
Ethylene glycol butyl ether
Ethylene glycol butyl ether acetate
Ethylene oxide
Enhanced oil recovery (new technology,
cf IOR)
Propylene glycol ethyl ether acetate
Expanded polystyrene
Emergency shutdown system
Electric submerged pump
Ethyl-tertiary-butyl-ether
143

F&G
FCC
FGS
FPSO
F-T
GB(S)
GE
GOR
GOSP
GRP
GTL
GTP
HAZID
HAZOP
HDPE
HFC
HDS
HIPPS
HP
HPU
HVAC
IMS
IO
IOR
IPA
IR
ISO
K-Mass Flow
LDPE
LLDPE
LNG
LP
LPG
LPG
LVOC
MCC
MEA
Fire & gas system
Fluid catalytic cracking
Field gathering station
Floating production storage and offloading
Fischer–Tropsch process
Gravity base structure
Glycol ether
Gas oil ratio from the well
Gas oil separation plant
Glass reinforced plastics
Gas to liquids
Gas treatment platform
Hazard identification study
Hazard and operability study
High-density polyethylene
Hydrofluorocarbons
Hydrodesulfurization (unit)
High integrity pressure (or pipeline)
protection system
High pressure
Hydraulic power unit
(topside utility for subsea)
Heat ventilation and air conditioning
Information management system
Integrated operations
Improved oil recovery
(using proven technology)
Isopropyl acetate
Infrared
International Standards Organization
Coriolis type sass flow meter
Low-density polyethylene
Linear low-density polyethylene
Liquid natural gas (e.g., methane)
Low pressure
Liquid petroleum gas
Liquefied petroleum gas (e.g., propane)
Large volume organic chemicals
Motor control center
Monoethanolamine
144

MEG
MEK
MMA
MP
MPA
MPG / USP
MSDS
MTBE
MTBF
NAO
NBR
NGL
NGL
OPEX
PCP
PD-Meter
PES
PET
PFD
PG
PGEE
PGEEA
PGME
PGMEA
PGP
PID
PIMS
PMMA
PO
PoC
POM
POSMOOR
PSD
PVC
ROV
Monoethylene glycol
Methyl ethyl ketone
Methyl methacrylate
Propylene glycol methyl ether
Propylene glycol methyl ether acetate
Pharmaceutical grade monopropylene
glycol
Material Safety Data Sheet
(international: SDS)
Methyl-tert-butyl-ether
Mean time between failure
Normal alpha olefins or n-olefins
( See alpha olefins)
Nitrile-butadiene rubber
Natural gas liquids
Natural gas liquids, condensates
(see also, LPG)
Operational expenses
Progressive cavity pump
Positive displacement meter
Unsaturated polyester resins
Polyethylene terephthalate
Probability of failure on demand
Propylene glycol
Propylene glycol ethyl ether
Propylene glycol ethyl ether acetate
Propylene glycol methyl ether
Propylene glycol methyl ether acetate
Power generation platform
Proportional integral derivate control algorithm
Production information management system
Polymethyl methacrylate
Propylene oxide
Pump of controller (for artificial lift)
Polyoxymethylene
Position mooring for a floating facility
Process shutdown system
Polyvinyl chloride
Remote operated vehicle
(for subsea workover)
145

RRF
Risk reduction factor
RTU
Remote terminal unit
SAN
Styrene-acrylonitrile
SAS
Safety and automation system
SBR
Styrene-butadiene rubber
SCADA
Supervisory control and data acquisition
SIF
Safety instrumented function
SIL Safety integrity level (per IEC 61508)
SIRC
SIS
Safety instrumented system
TAED
Tetraacetylethylenediamine
TAME
Tertiary-amyl-methyl-ether
TBA
Tertiary-butyl-alcohol
TDI
Toluene di-isocyanate
TEA
Triethanolamine
TEPA
Tetraethylenepentamine
TIP
Tie-in platform
TLP
Tension leg platform
UMS
Unmanned machinery space class
(marine = E0)
uPES, UPR, USPE Unsaturated polyester resins
URF
Umbilicals, risers and flowlines
UV
Ultraviolet
VAM
Vinyl acetate monomer
VCM
Vinyl chloride monomer
VDU
Vacuum distillation unit
VOC
Volatile organic compound
WHP
Well head platform
XPS
Extruded polystyrene
146

12 References
Web online sources and references that have been used in compiling this
document:
• Schlumberger Oilfield Glossary
http://www.glossary.oilfield.slb.com/
• Statoil, Fact sheet Njord
http://www.statoil.com/en/OurOperations/ExplorationProd/ncs/njord/Pages/default.aspx
• International Energy Agency (IEA) -Key World Energy Statistics 2012
http://www.iea.org/publications/freepublications/publication/name,31287,en.html
• Wikipedia
http://en.wikipedia.org/wiki/Main_Page
• Oklahoma State, Marginal Well Commission, Pumper's Manual
http://www.marginalwells.com/MWC/pumper_manual.htm (Discontinued)
• Natural Gas Supply Association. See Natural Gas - From Wellhead to
Burner Tip http://www.naturalgas.org/naturalgas/naturalgas.asp
• US geological survey:
http://www.usgs.gov/
• US Department of Energy:
http://www.doe.gov/
• NORSOK Standards, Standards Norway (SN),
http://www.standard.no/en/sectors/Petroleum/
• UK Offshore Operators Association (UKOOA) – For Students
http://www.oilandgas.org.uk/education/students/intro.cfm
• National Biodiesel Board
http://www.biodiesel.org/
• PBS – Public Broadcasting Service - Extreme Oil
http://www.pbs.org/wnet/extremeoil/index.html
• The Story of Oil in Pennsylvania
http://www.priweb.org/ed/pgws/history/pennsylvania/pennsylvania.html
• Air Liquide Gas Encyclopedia
http://encyclopedia.airliquide.com/encyclopedia.asp
147

13 Index
ABS ..................................... 92, 95
absorption ................................. 63
acid gas ..................................... 61
acid gas removal ....................... 63
acronyms ................................ 143
acrylonitrile-butadiene-styrene . 92,
95
actuator ................................... 101
additives .................................... 86
adsorbtion ................................. 63
alkanes ...................................... 21
alkyd resins ............................... 90
alkylates .................................... 84
alkylation unit ............................ 83
amine gas treater ...................... 84
Ammonia ................................... 99
anti surge ............................ 48, 53
antifoam .................................. 122
API .................................. 141, 142
API grade .................................. 21
aromatic petrochemicals ........... 87
aromatics ............................ 21, 88
Aromatics .................................. 19
artificial lift ................................. 35
Asphalt ...................................... 80
asset optimization ................... 113
atmospheric distillation .............. 82
atmospheric ventilation ........... 119
auto-refrigeration ....................... 76
axial compressor .................... 51
ballast systems ....................... 121
Barrel....................................... 141
beam pump ............................... 35
biocides ................................... 123
biofuels .................................... 133
Bitumen ..................................... 80
blending .................................... 85
Block valve stations ............ 68, 69
blow out ..................................... 28
blow-down ......................... 45, 119
Bunker....................................... 80
butadiene .................................. 96
butylenes .................................. 96
calorific value ............................ 65
carbon capture ........................ 140
carbon number .......................... 22
casing........................................ 29
catalytic reformer unit ............... 82
cause and affect chart ............ 106
CCR ........................................ 102
Central Control Room ............. 102
centrifugal compressors ........ 52
chemical additives .................. 121
choke valve ............................... 34
christmas tree ........................... 32
Claus process ........................... 84
CNG .......................................... 61
CO 2 ......................................... 136
coal ......................................... 131
coal bed methane ................... 130
coalescer .................................. 46
co-distribution ........................... 85
coiled tubing .............................. 39
coke .......................................... 80
coking unit ................................. 83
communication systems ......... 125
completion ................................ 31
compliant towers ......................... 9
compressor ............................... 50
condensate ......................... 24, 61
condition monitoring ................ 114
cone bit ..................................... 26
control valves .......................... 100
controller ................................. 101
coriolis massflow ....................... 56
corrosion inhibitor ................... 124
crude oil .................................... 21
cryogenic removal ..................... 63
148

cumene .................................... 95
custody transfer .................. 15, 55
DEA ........................................... 93
deluge ..................................... 107
depressurisation ...................... 119
derrick ....................................... 26
dew point ................................... 66
diesel ......................................... 23
Diesel oil ................................... 79
dimerization ............................... 84
dimethyl terephthalate............ 98
directional drilling ...................... 27
distillate hydrotreater ................. 83
distribution ................................. 85
DMT .......................................... 98
downhole pump ......................... 36
drag reducers .......................... 124
Drake .......................................... 1
drawworks ................................. 26
drill string ................................... 26
drilling ........................................ 26
dry gas ...................................... 60
electric power .......................... 117
emergency shutdown .............. 105
emissions ................................ 135
emulsion breaker .................... 122
energy efficiency ..................... 139
environmental impact .............. 136
Epoxy resin ............................... 91
ESD ......................................... 105
ESP ........................................... 36
ethanol .............................. 93, 133
ethanolamines ........................... 93
Exploration .................................. 4
explosive hazard ..................... 102
F&G ......................................... 108
facilities ....................................... 5
FCC ........................................... 83
fieldbus .................................... 101
fire and gas system ................. 107
fire area ................................... 107
fire damper .............................. 107
fire detection ........................... 107
149
firefighting ............................... 107
Fischer–Tropsch process . 98, 131
flare ......................................... 119
flash-drum ................................. 45
floating production ...................... 9
fluid catalytic cracker ................ 83
FPSO ........................................ 10
fractional distillation .................. 77
fracturing ................................... 39
free flowing well ........................ 35
Fuel oil ...................................... 80
functional safety ...................... 103
gas ............................................ 23
gas compression ....................... 17
gas detection .......................... 107
gas oil separation plant (GOSP) . 7
Gas Plants ................................ 16
Gas to Liquids ......................... 132
gas volume ............................... 65
gasoline .............................. 23, 79
gathering ................................... 13
glycol ................................. 50, 123
gravity base ................................ 9
greenhouse gas ...................... 136
HAZID ..................................... 103
HAZOP ................................... 103
HDPE ........................................ 94
heat exchanger ......................... 48
heavy crude ............................ 128
HIPPS ....................................... 70
history ......................................... 1
horizontal tree ........................... 34
horizontal well ........................... 27
HVAC ...................................... 120
hydrocracker ............................. 83
hydrocyclone ............................. 47
hydrogen ................................. 135
hydrogen sulfide ....................... 66
hypochlorite ............................ 123
information management system
............................................ 115
injection wells ............................ 35
instrument air .......................... 120

instrumentation ....................... 101
integrated manufacturing .......... 88
isomerization ............................. 84
Kerosene ................................... 79
kill fluid ...................................... 28
LDPE ......................................... 94
Leak detection ........................... 70
Liquid Pipelines ......................... 68
LLDPE ....................................... 94
LNG ..................................... 61, 70
Carrier ................................... 76
Cascade cycle ....................... 71
Expander cycle ...................... 72
liquefaction ............................ 74
Liquefaction ........................... 71
Mixed refrigerant cycle .......... 71
pre-cooling ............................. 74
sub-cooling ............................ 74
terminal .................................. 76
LNG Liquefaction ...................... 18
loading....................................... 58
LPG ..................................... 61, 78
lubricant .................................... 80
maintenance ........................... 113
manifold .............................. 13, 42
massflow meter ......................... 57
master valve .............................. 33
MCC ........................................ 118
MEA .......................................... 93
melamine resin ........................ 98
mercury removal ....................... 64
merox ........................................ 83
metaxylene ................................ 89
metering .................................... 15
methane hydrates ................... 132
methanol ........................... 98, 132
Methanol (MEG) ..................... 123
methyl methacrylate ............... 95
methyl-tert-butyl-ether ............ 97
midstream ................................. 16
MMA .......................................... 95
MTBE ........................................ 97
mud ........................................... 26
150
naphtha ..................................... 79
naphtha hydrotreater ................ 82
natural gas .......................... 23, 61
NGL ..................................... 24, 61
NGL recovery ............................ 65
nitrogen rejection ...................... 65
Njord ......................................... 40
Nylon ......................................... 90
octane ....................................... 79
offshore facilities ......................... 8
compliant towers ..................... 9
floating production ................... 9
gravity base ............................. 9
shallow water .......................... 9
subsea production systems .. 12
oil shale gas ............................ 130
olefins........................................ 87
Olefins ................................ 19, 92
onshore production ..................... 7
operator station ....................... 101
orthoxylene ............................... 90
OSPAR ..................................... 47
P&ID ........................................ 108
PAN ........................................... 95
paraffin ...................................... 79
paraxylene ................................ 89
PCP ........................................... 36
PE ............................................. 94
performance control .................. 53
Petrochemical ........................... 19
Petrochemicals ......................... 87
petrodiesel ................................ 79
Phenol ....................................... 91
phenol pormaldehyde ............... 98
Phenolic resins ......................... 91
Pig tracking ............................... 70
Pipeline ..................................... 67
Pipeline management ............... 69
Pipeline Modeling ..................... 69
Pipelines ................................... 67
Piping and Instrumentation
Diagrams ............................. 108
polyacrylonitrile ......................... 95

polybutadiene ............................ 96
polybutylene .............................. 97
Polycarbonates ......................... 91
polyelectrolyte ......................... 123
polyethylene .............................. 94
polyisobutylene ......................... 96
polymerization ........................... 88
polypropylene ......................... 94
polystyrene ................................ 91
polyurethane ........................... 95
pores ......................................... 25
potable water .......................... 120
power generation .................... 117
power management system .... 118
PP ............................................. 94
Primary petrochemicals ............ 87
Probability of Failure on Demand
............................................. 105
process control system ........... 100
process overview ........................ 4
process shutdown ................... 105
production optimization ........... 112
production separator ................. 43
prover loop ................................ 55
PSD ......................................... 105
public address ......................... 124
pygas ........................................ 96
Q/T curve .................................. 72
radial compressors ................. 52
reciprocating compressor ......... 51
references ............................... 147
refinery ...................................... 23
Refining ............................... 18, 77
regasification ............................. 18
remote operations ................... 112
reservoir .................................... 24
reservoir management ............ 112
reservoir stimulation .................. 39
riser ........................................... 42
rod pump ................................... 35
RTU ......................................... 110
salt domes ................................. 25
SAN ........................................... 92
151
SBR........................................... 92
SCADA ................................... 110
scale inhibitor .......................... 122
SCD ........................................ 110
SCF ......................................... 141
SCM ........................................ 141
Scraper tracking ........................ 70
screw compressors ................ 51
scrubber .................................... 49
seawater ................................. 121
security systems ..................... 126
semisubmersible ....................... 11
separation ................................. 14
separator ................................... 43
sequestration .......................... 140
Sevan Marine FPSO ................. 11
shale ......................................... 24
shale gas ................................ 130
shallow water .............................. 9
shutdown .................................. 45
slug catcher .............................. 44
slugging .................................... 42
sour gas .................................... 60
SPAR ........................................ 11
sprinklers ................................ 107
steam reforming ........................ 84
storage ................................ 15, 57
styrene-acrylonitrile ................... 92
Styrene-butadiene rubber ......... 92
subsea production systems ...... 12
subsea separation .................... 34
subsea wells ............................. 34
sweetening ................................ 59
switchboard ............................. 118
syngas ...................................... 97
synthesis gas ............................ 87
Synthesis gas .................... 19, 97
synthetic rubber ........................ 92
System Control Diagram......... 110
tail gas treatment ...................... 64
tankfarm .................................... 58
tar .............................................. 80
tar sands ................................. 128

TEA ........................................... 93
TEG ........................................... 49
telecommunication systems .... 124
telemetry ................................. 110
terminal ..................................... 67
terminal management system ... 86
terminals ................................... 19
test separator ............................ 43
TLP ............................................ 11
TOE ......................................... 141
tolune diisocyanate ................... 90
training simulator ..................... 116
Tri Ethylene Glycol (TEG) ....... 123
ultrasonic meter ........................ 56
umbilical .................................... 34
unconventional sources .......... 127
units ......................................... 141
urea ........................................... 99
urea-formaldehyde .................... 98
utility system ..................... 16, 100
vertical tree ............................... 34
visbreaking ................................ 83
vortex breakers ......................... 44
water treatment ......................... 46
well ...................................... 27, 29
casing .................................... 29
completion ............................. 31
wellhead ................................ 32
well intervention ........................ 38
well workover ............................ 38
wellhead .......................... 7, 12, 32
wet gas...................................... 60
wing valve ................................. 33
wireline operations .................... 38
wobbe index .............................. 66
workover ................................... 38
152

153

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